National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters, 7137-7213 [2012-31646]
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Vol. 78
Thursday,
No. 21
January 31, 2013
Part V
Environmental Protection Agency
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40 CFR Part 63
National Emission Standards for Hazardous Air Pollutants for Major
Sources: Industrial, Commercial, and Institutional Boilers and Process
Heaters; Final Rule
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Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 63
[EPA–HQ–OAR–2002–0058; FRL–9676–8]
RIN 2060–AR13
National Emission Standards for
Hazardous Air Pollutants for Major
Sources: Industrial, Commercial, and
Institutional Boilers and Process
Heaters
Environmental Protection
Agency (EPA).
ACTION: Final rule; notice of final action
on reconsideration.
AGENCY:
In this action the EPA is
taking final action on its reconsideration
of certain issues in the emission
standards for the control of hazardous
air pollutants from new and existing
industrial, commercial, and institutional
boilers and process heaters at major
sources of hazardous air pollutants,
which were issued under section 112 of
the Clean Air Act. As part of this action,
the EPA is making technical corrections
to the final rule to clarify definitions,
references, applicability and compliance
issues raised by petitioners and other
stakeholders affected by this rule. On
March 21, 2011, the EPA promulgated
national emission standards for this
source category. On that same day, the
EPA also published a notice announcing
its intent to reconsider certain
provisions of the final rule. Following
these actions, the Administrator
received several petitions for
reconsideration. After consideration of
the petitions received, on December 23,
2011, the EPA proposed revisions to
certain provisions of the March 21,
2011, final rule, and requested public
comment on several provisions of the
final rule. The EPA is now taking final
action on the proposed reconsideration.
DATES: The May 18, 2011 (76 FR28661),
delay of the effective date revising
subpart DDDDD at 76 FR 15451 (March
21, 2011) is lifted January 31, 2013. The
amendments in this rule to 40 CFR part
63, subpart DDDDD are effective as of
April 1, 2013.
ADDRESSES: The EPA established a
single docket under Docket ID No. EPA–
HQ–OAR–2002–0058 for this action. All
documents in the docket are listed on
the https://www.regulations.gov Web
site. Although listed in the index, some
information is not publicly available,
e.g., confidential business information
or other information whose disclosure is
restricted by statute. Certain other
material, such as copyrighted material,
is not placed on the Internet and will be
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SUMMARY:
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publicly available only in hard copy
form. Publicly available docket
materials are available either
electronically through https://
www.regulations.gov or in hard copy at
the EPA’s Docket Center, Public Reading
Room, EPA West Building, Room 3334,
1301 Constitution Avenue NW.,
Washington, DC 20004. This Docket
Facility is open from 8:30 a.m. to 4:30
p.m., Monday through Friday, excluding
legal holidays. The telephone number
for the Public Reading Room is (202)
566–1744, and the telephone number for
the Air Docket is (202) 566–1742.
FOR FURTHER INFORMATION CONTACT: Mr.
Jim Eddinger, Energy Strategies Group,
Sector Policies and Programs Division,
(D243–01), Office of Air Quality
Planning and Standards, U.S.
Environmental Protection Agency,
Research Triangle Park, North Carolina
27711; Telephone number: (919) 541–
5426; Fax number (919) 541–5450;
Email address: eddinger.jim@epa.gov.
SUPPLEMENTARY INFORMATION:
Executive Summary
Purpose of This Regulatory Action
The EPA is taking final action on its
proposed reconsideration of certain
provisions of its March 21, 2011, final
rule that established standards for new
and existing industrial, commercial, and
institutional boilers and process heaters
at major sources of hazardous air
pollutants. Section 112(d) of the CAA
requires the EPA to regulate HAP from
major stationary sources based on the
performance of MACT. Section 112(h) of
the CAA allows the EPA to establish
work practice standards in lieu of
numerical emission limits only in cases
where the agency determines that it is
not feasible to prescribe or enforce an
emission standard, including
circumstances in which the agency
determines that the application of
measurement methodology is not
practicable due to technological and
economic limitations. The EPA is
revising certain MACT standards
established in March 2011 for boilers
and process heaters, including
standards for CO—as a surrogate for
organic HAP; HCl—as a surrogate for
acid gas HAP; Hg; TSM or filterable
PM—as a surrogate for non-Hg metallic
HAP; and dioxin/furan.
This final rule amends certain
provisions of the final rule issued by the
EPA on March 21, 2011. The EPA
delayed the effective date of the 2011
rule in a May 18, 2011, notice, but that
delay notice was vacated by the U.S.
District Court for the District of
Columbia on January 9, 2012, and the
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March 2011 final rule was, therefore, in
effect until publication of this action.
Summary of Major Reconsideration
Provisions
In general, this final rule requires
facilities classified as major sources of
HAP with affected boilers or process
heaters to reduce emissions of harmful
toxic air emissions from these
combustion sources. This will improve
air quality and protect public health in
communities where these facilities are
located.
Recognizing the diversity of this
source category and the multiple sectors
of the economy this final rule effects,
the EPA is revising certain subcategories
for boilers and process heaters in this
action that were established in the
March 2011 final rule, based on the
design of the combustion equipment.
These revisions result in 19
subcategories for the boilers and process
heaters source category. Numerical
emission limits are established for most
of the subcategories for five pollutants,
CO, HCl, Hg, and PM or TSM. The
review of existing data and
consideration of new data have resulted
in changes to some of the emission
limits contained in the March 2011 final
rule. Overall, for both new and existing
affected units, about 30 percent of the
emission limits are more stringent, half
are less stringent, and 20 percent
unchanged as compared to the March
2011 final rule. Also, based on its
review and analysis of new data
submissions, the EPA is establishing an
alternative emission standard for CO,
based on CEMS data for several
subcategories with CO CEMS data
available. This alternative standard is
based on a 30-day rolling average for
subcategories for which sufficient CEMS
data were available for more than a 30day period, or a 10-day rolling average
for subcategories for which CEMS data
were available for less than a 30-day
period, and provides additional
compliance flexibility to sources. All of
the subcategories are subject to periodic
tune-up work practices for dioxin/furan
emissions.
The compliance dates for the rule are
January 31, 2016, for existing sources
and, January 31, 2013, or upon startup,
whichever is later, for new sources. New
sources are defined as sources that
began operation on or after June 4, 2010.
Costs and Benefits
The final rule affects 1,700 existing
major source facilities with an estimated
14,136 boilers and process heaters and
the EPA projects an additional 1,844
new boilers and process heaters to be
subject to this final rule over the next 3
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years. This final rule affects multiple
sectors of the economy including small
entities. Table 1 summarizes the costs
and benefits associated with this final
rule. A more detailed discussion of the
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costs and benefits of this final rule is
provided in section VI of this preamble.
TABLE 1—SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS AND NET BENEFITS FOR THE FINAL BOILER MACT
RECONSIDERATION IN 2015
[Millions of 2008$] 1
3 percent discount
rate
7 percent discount
rate
Total Monetized Benefits 2 ...............................................................................................................
Total Social Costs 3 .........................................................................................................................
Net Benefits .....................................................................................................................................
$27,000 to $67,000 ...
$1,400 to $1,600 .......
$26,000 to $65,000 ...
Non-monetized Benefits ..................................................................................................................
Health effects from exposure to HAP (39,000
tons of HCl, 500 tons of HF, 3,100 to 5,300
pounds of Hg and 2,500 tons of other metals).
Health effects from exposure to other criteria
pollutants (180,000 tons of CO and 572,000
tons of SO2).
Ecosystem effects.
Visibility impairment.
$25,000 to $61,000.
$1,400 to $1,600.
$23,000 to $59,000.
1 All
estimates are for the implementation year (2015), and are rounded to two significant figures.
total monetized co-benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of PM2.5
precursors such as directly emitted particles, SO2, and NOX and reducing exposure to ozone through reductions of VOC. It is important to note
that the monetized benefits include many but not all health effects associated with PM2.5 exposure. Monetized benefits are shown as a range
from Pope et al. (2002) to Laden et al. (2006). These models assume that all fine particles, regardless of their chemical composition, are equally
potent in causing premature mortality because the scientific evidence is not yet sufficient to support the development of differential effects estimates by particle type. These estimates include the energy disbenefits valued at $24 million (using the 3 percent discount rate), which do not
change the rounded totals. CO2-related disbenefits were calculated using the ‘‘social cost of carbon,’’ which is discussed further in the RIA.
3 The methodology used to estimate social costs for one year in the multimarket model using surplus changes results in the same social costs
for both discount rates.
2 The
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Acronyms and Abbreviations. The
following acronyms and abbreviations
are used in this document.
ACC American Chemistry Council
ACCCI American Coke and Coal Chemicals
Institute
AF&PA American Forest and Paper
Association
AHFA American Home Furnishings
Alliance
AISI American Iron and Steel Institute
AMP American Municipal Power Inc.
AIE Alliance for Industrial Efficiency
APCD air pollution control devices
API American Petroleum Institute
AIF Auto Industry Forum
BFG Blast furnace gas
BLDS Bag leak detection system
BCSE The Business Council for Sustainable
Energy
CIBO Council of Industrial Boiler Owners
CO Carbon monoxide
CO2 Carbon dioxide
CEMS Continuous emissions monitoring
system
CEG Citizens Energy Group
CAA Clean Air Act
CFR Code of Federal Regulations
CPMS Continuous parameter monitoring
system
CMI CraftMaster Manufacturing Inc.
ERT Electronic Reporting Tool
ESP Electrostatic precipitator
EPA Environmental Protection Agency
FBC Fluidized bed combustion
FR Federal Register
FSI Florida Sugar Industry
GPSP Great Plains Synfuels Plant
HAP Hazardous air pollutants
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HBES Health-based emissions standard
HF Hydrogen fluoride
Hg Mercury
HCl Hydrogen chloride
kWh Kilowatt hours
ISO International Standards Organization
lb Pounds
LFG Landfill gas
MACT Maximum achievable control
technology
MATS Mercury Air Toxics Standards
MSU Michigan State University
MMBtu Million British thermal units
NESHAP National Emission Standards for
Hazardous Air Pollutants
NPRA National Petrochemical and Refiners
Association
NTTAA National Technology Transfer and
Advancement Act
NAICS North American Industry
Classification System
NOX Nitrogen oxide
NSR New Source Review
OMB Office of Management and Budget
PM Particulate matter
PSU Penn State University
PS Performance Specification
ppm Parts per million
QA Quality assurance
QC Quality control
RFA Regulatory Flexibility Act
RIA Regulatory Impact Analysis
RPU Rochester Public Utilities
RTC Response to comment
SCR Selective catalytic reduction
SNCR Selective non-catalytic reduction
SO2 Sulfur dioxide
TBtu/yr Trillion British thermal units per
year
THC Total hydrocarbon
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TSM Total selected metals
TTN Technology Transfer Network
tpy Tons per year
UMRA Unfunded Mandates Reform Act of
1995
U.S. United States
USCHPA US Clean Heat Power Association
US Sugar United States Sugar Corporation
UPL Upper prediction limit
UARG Utility Air Regulatory Group
VCS Voluntary Consensus Standards
VOC Volatile organic compounds
WM Waste Management Inc.
WEPCO Wisconsin Electric Power
Company
WWW Worldwide Web
Organization of this Document. The
information presented in this preamble
is organized as follows:
I. General Information
A. Does this action apply to me?
B. Where can I get a copy of this
document?
C. Judicial Review
II. Background Information
A. Chronological History of Related
Actions
III. Summary of This Final Rule
A. What is an affected source?
B. What are the subcategories of boilers
and process heaters?
C. What emission limits and work practice
standards are being finalized?
D. What are the requirements during
periods of startup and shutdown?
E. What are the testing and initial
compliance requirements?
F. What are the continuous compliance
requirements?
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G. What are the compliance dates?
IV. Summary of Significant Changes Since
Proposal
A. Applicability
B. Subcategories
C. Performance Test Requirements
D. Emission Limits
E. Work Practice Requirement
F. Averaging Times Definitions
G. Energy Assessment
H. Startup and Shutdown Definitions
I. Fuel Sampling Frequency
J. Affirmative Defense
V. Other Actions We Are Taking
VI. Impacts of This Final Rule
A. What are the incremental air impacts?
B. What are the incremental water and
solid waste impacts?
C. What are the incremental energy
impacts?
H. Executive Order 13211: Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use
I. National Technology Transfer and
Advancement Act
J. Executive Order 12898: Federal Actions
to Address Environmental Justice in
Minority Populations and Low-Income
Populations
K. Congressional Review Act
D. What are the incremental cost impacts?
E. What are the economic impacts?
F. What are the benefits of this final rule?
G. What are the incremental secondary air
impacts?
VII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory
Planning and Review and Executive
Order 13563: Improving Regulation and
Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation
and Coordination with Indian Tribal
Governments
G. Executive Order 13045: Protection of
Children from Environmental Health
Risks and Safety Risks
I. General Information
A. Does this action apply to me?
The regulated categories and entities
potentially affected by this action
include:
TABLE 2—POTENTIAL REGULATED CATEGORIES AND ENTITIES AFFECTED
NAICS code1
Category
Any industry using a boiler or process heater as defined in the final rule ............
Examples of potentially regulated entities
211
321
322
325
324
316, 326,
339
331
332
336
221
622
611
1 North
American Industry Classification System.
This table is not intended to be
exhaustive, but rather provides a guide
for readers regarding entities likely to be
regulated by this reconsideration action.
To determine whether your facility may
be affected by this reconsideration
action, you should examine the
applicability criteria in 40 CFR 63.7485
of subpart DDDDD (National Emission
Standards for Hazardous Air Pollutants
(NESHAP) for Industrial, Commercial,
and Institutional Boilers and Process
Heaters). If you have any questions
regarding the applicability of this final
rule to a particular entity, consult either
the air permitting authority for the
entity or your EPA regional
representative, as listed in 40 CFR 63.13
of subpart A (General Provisions).
B. Where can I get a copy of this
document?
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Extractors of crude petroleum and natural
gas.
Manufacturers of lumber and wood products.
Pulp and paper mills.
Chemical manufacturers.
Petroleum refineries, and manufacturers
of coal products.
Manufacturers of rubber and miscellaneous plastic products.
Steel works, blast furnaces.
Electroplating, plating, polishing, anodizing, and coloring.
Manufacturers of motor vehicle parts and
accessories.
Electric, gas, and sanitary services.
Health services.
Educational services.
In addition to being available in the
docket, an electronic copy of this action
will also be available on the WWW
through the TTN. Following signature, a
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copy of the action will be posted on the
TTN’s policy and guidance page for
newly proposed or promulgated rules at
the following address: https://
www.epa.gov/ttn/oarpg/. The TTN
provides information and technology
exchange in various areas of air
pollution control.
C. Judicial Review
Under the CAA section 307(b)(1),
judicial review of this final rule is
available only by filing a petition for
review in the U.S. Court of Appeals for
the District of Columbia Circuit by April
1, 2013. Under CAA section
307(d)(7)(B), only an objection to this
final rule that was raised with
reasonable specificity during the period
for public comment can be raised during
judicial review. Note, under CAA
section 307(b)(2), the requirements
established by this final rule may not be
challenged separately in any civil or
criminal proceedings brought by the
EPA to enforce these requirements.
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II. Background Information
A. Chronological History of Related
Actions
On March 21, 2011, the EPA issued
final standards for new and existing
industrial, commercial, and institutional
boilers and process heaters, pursuant to
its authority under section 112 of the
CAA. On the same day as the final rule
was issued, the EPA stated in a separate
notice that it planned to initiate a
reconsideration of several provisions of
the final rule. This reconsideration
notice identified several provisions of
the March 2011 final rule where
additional public comment was
appropriate. This notice also identified
several issues of central relevance to the
rulemaking where reconsideration was
appropriate under CAA section 307(d).
On May 18, 2011, the EPA issued a
notice to postpone the effective date of
the March 21, 2011 final rule. Following
promulgation of the final rule, the EPA
received petitions for reconsideration
from the following organizations
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(‘‘Petitioners’’): AIE, USCHPA, Alyeska
Pipeline, ACC, AHFA, AISI, ACCCI,
AMP, API, NPRA, AIF, Citizens Energy
Group (CEG), CIBO, CMI, District
Energy St. Paul, FSI, GPSP, Hovensa
L.L.C., Tesoro Hawaii Corp., Industry
Coalition (AF&PA et al.), JELD–WEN
Inc., MSU, PSU, Purdue University,
Renovar Energy Corp., RPU, Sierra Club,
Southeastern Lumber Manufacturers
Association, State of Washington
Department of Ecology, BCSE, UARG,
US Sugar, WM and WEPCO. Copies of
these petitions are provided in the
docket (see Docket ID No. EPA–HQ–
OAR–2002–0058). Petitioners, pursuant
to CAA section 307(d)(7)(B), requested
that the EPA reconsider numerous
provisions in the rule. On December 23,
2011, the EPA granted the petitions for
reconsideration on certain issues, and
proposed certain revisions to the final
rule in response to the reconsideration
petitions and to address the issues that
the EPA previously identified as
warranting reconsideration. That
proposal solicited comment on several
specific aspects of the rule, including:
• Revising the proposed
subcategories.
• Solicitation of new data or
corrections to existing data to revise
emission standards calculations.
• Establishing an alternative TSM
limit.
• Appropriateness of an alternative
TSM limit for the liquid subcategories.
• Establishing work practice
standards for dioxin/furan emissions.
• Revising the efficiency assumptions
for the alternative output-based
emission standards.
• Accommodating emissions
averaging provisions in the alternative
output-based emission standards.
• Establishing a mercury fuel
specification through which gas-fired
boilers that use a fuel other than natural
gas or refinery gas may be considered
Gas 1 units.
• Establishing a work practice
standard for limited use units.
• Providing an affirmative defense for
malfunction events.
• Revisions to the monitoring
requirements for oxygen in the March
2011 final rule.
• Establishing a full-load stack test
requirement for carbon monoxide
coupled with continuous oxygen
(oxygen trim) monitoring.
• Revising PM monitoring
requirements from CEMS to CPMS and
exempting biomass units from PM
CPMS requirements.
• Revising mercury monitoring
requirements to allow for an alternative
mercury CEMS.
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• Considering use of SO2 CEMS to
demonstrate compliance with HCl
limits.
• Minimum data availability
provisions.
• Averaging times for monitored
parameters and pollutants.
• Revised methods for computing
minimum detection levels.
• Providing an alternative CO
emission limit based on CO CEMS data.
• Soliciting additional data to set
MACT floor emission limits for noncontinental liquid units.
• Selecting a 99 percent confidence
interval for setting the CO emission
limit.
• Tune-up frequencies, timing of
initial tune-ups and adjusted tune-up
requirements for shutdown units.
• Scope and duration of the energy
assessment and deadline for completing
the assessment.
• Revising work practices during
startup and shutdown.
• Revisions to certain exemptions,
including units serving as control
devices, waste heat process heaters,
units firing comparable fuels and
residential units.
• Revisions to reduced testing
frequency for emission limits that are
established at minimum detection
levels.
• Removing fuel analysis
requirements for gas 1 fuels at co-fired
units.
• Revisions to automating techniques
for coal sampling.
• Revisions to emissions averaging
across subcategories when units opt to
switch to natural gas.
• Consideration of a new subcategory
for units installed and used in place of
flares.
In this action, the EPA is finalizing
multiple changes to the March 2011
final rule after considering public
comments on the items under
reconsideration.
III. Summary of This Final Rule
As stated above, the December 23,
2011 proposed rule addressed specific
issues and provisions the EPA identified
for reconsideration. This summary of
the final rule reflects the changes to 40
CFR part 63, subpart DDDDD (March 21,
2011 final rule) in regards to those
provisions identified for reconsideration
and on other discrete matters identified
in response to comments or data
received during the comment period.
Information on other provisions and
issues not proposed for reconsideration
is contained in the notice and record for
the 2011 final rule. [See 76 FR 15608]
This section summarizes the
requirements of this action. Section IV
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below provides a summary of the
significant changes to the March 21,
2011 final rule.
A. What is an affected source?
This final rule revises the list of
exemptions in § 63.7491 to include
residential boilers that may be located at
an industrial, commercial or
institutional major source. The
exemption for boilers or process heaters
used specifically for research and
development has been revised to
include boilers used for certain testing
purposes.
B. What are the subcategories of boilers
and process heaters?
In this final rule, we are finalizing
separate subcategories for heavy liquidfired, light liquid-fired and liquid-fired
units in non-continental locations for
PM and CO, pollutants that are
dependent on combustor design. In
addition, a new subcategory for coalfired fluidized bed boilers with
integrated fluidized bed heat exchangers
has been included in the final rule for
CO which is dependent on boiler
design. Finally, we are finalizing the
subcategory for PM at coal/fossil solid
units across all coal combustor designs.
C. What emission limits and work
practice standards are being finalized?
You must meet the emission limits
presented in Table 3 of this preamble for
each subcategory of units listed in the
table. This final rule includes 19
subcategories, which are based on unit
design. New and existing units in three
of the subcategories are subject to work
practices standards in lieu of emission
limits for all pollutants. Numeric
emission limits are finalized for new
and existing sources in each of the other
16 subcategories.
The changes associated with the
emission limits are due to new data,
corrections to old data, and inventory
changes. In summary, for existing
subcategories, for the HCl emission
limits, 10 are more stringent, 3 are less
stringent and 1 remained the same from
the March 21, 2011 final rule; for the
mercury emission limits, 3 are more
stringent and 11 are less stringent from
the March 21, 2011 final rule; for the
PM emission limits, 2 are more
stringent, 7 are less stringent and 5 are
unchanged from the March 21, 2011
final rule; and for the CO emission
limits, 4 are more stringent and 10 are
less stringent from the March 21, 2011
final rule. For new subcategories, for the
HCl emission limits, 13 are less
stringent and 1 is unchanged from the
March 21, 2011 final rule; for the
mercury emission limits, 11 are more
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stringent, 2 are less stringent and 1 is
unchanged from the March 21, 2011
final rule; for the PM emission limits, 9
are less stringent and 5 are unchanged
from the March 21, 2011 final rule; and
for the CO emission limits, 3 are more
stringent and 11 are less stringent from
the March 21, 2011 final rule.
TABLE 3—EMISSION LIMITS FOR BOILERS AND PROCESS HEATERS
[lb/MMBtu heat input basis unless noted; alternative output based limits are not shown in the summary table below]
Subcategory
Filterable PM
(or total selected
metals)
(lb per MMBtu of
heat input) a
Existing—Coal Stoker ...............................................................
Existing—Coal Fluidized Bed ....................................................
Existing—Coal Fluidized Bed with FB heat exchanger ............
Existing—Coal-Burning Pulverized Coal ...................................
Existing—Biomass Wet Stoker/Sloped Grate/Other .................
Existing—Biomass Kiln-Dried Stoker/Sloped Grate/Other ........
Existing—Biomass Fluidized Bed .............................................
Existing—Biomass Suspension Burner .....................................
Existing—Biomass Dutch Ovens/Pile Burners ..........................
Existing—Biomass Fuel Cells ...................................................
Existing—Biomass Hybrid Suspension Grate ...........................
Existing—Heavy Liquid .............................................................
Existing—Light Liquid ................................................................
Existing—non-Continental Liquid ..............................................
Existing—Gas 2 (Other Process Gases) ..................................
New—Coal Stoker .....................................................................
New—Coal Fluidized Bed .........................................................
New—Coal Fluidized Bed with FB Heat Exchanger .................
New—Coal-Burning Pulverized Coal ........................................
New—Biomass Wet Stoker/Sloped Grate/Other ......................
New—Biomass Kiln-Dried Stoker/Sloped Grate/Other .............
New—Biomass Fluidized Bed ...................................................
New—Biomass Suspension Burner ..........................................
New—Biomass Dutch Ovens/Pile Burners ...............................
New—Biomass Fuel Cells .........................................................
New—Biomass Hybrid Suspension Grate ................................
New—Heavy Liquid ...................................................................
New—Light Liquid .....................................................................
New—Non-Continental Liquid ...................................................
New—Gas 2 (Other Process Gases) ........................................
0.040 (5.3E–05) ...
0.040 (5.3E–05) ...
0.040 (5.3E–05) ...
0.040 (5.3E–05) ...
0.037 (2.4E–04) ...
0.32 (4.0E–03) .....
0.11 (1.2E–03) .....
0.051 (6.5E–03) ...
0.28 (2.0E–03) .....
0.020 (5.8E–03) ...
0.44(4.5E–04) ......
0.062 (2.0E–04) ...
0.0079 (6.2E–05)
0.27 (8.6E–04) .....
0.0067 (2.1E–04)
0.0011 (2.3E–05)
0.0011 (2.3E–05)
0.0011 (2.3E–05)
0.0011 (2.3E–05)
0.030 (2.6E–05) ...
0.030 (4.0E–03) ...
0.0098 (8.3E–05)
0.030 (6.5E–03) ...
0.0032 (3.9E–05)
0.020 (2.9E–05) ...
0.026 (4.4E–04) ...
0.013 (7.5E–05) ...
0.0011 (2.9E–05)
0.023 (8.6E–04) ...
0.0067 (2.1E–04)
HCl
(lb per
MMBtu of
heat
input) a
Mercury
(lb per
MMBtu of
heat
input) a
0.022
0.022
0.022
0.022
0.022
0.022
0.022
0.022
0.022
0.022
0.022
0.0011
0.0011
0.0011
0.0017
0.022
0.022
0.022
0.022
0.022
0.022
0.022
0.022
0.022
0.022
0.022
4.4E–04
4.4E–04
4.4E–04
0.0017
5.7E–06
5.7E–06
5.7E–06
5.7E–06
5.7E–06
5.7E–06
5.7E–06
5.7E–06
5.7E–06
5.7E–06
5.7E–06
2.0E–06
2.0E–06
2.0E–06
7.9E–06
8.0E–07
8.0E–07
8.0E–07
8.0E–07
8.0E–07
8.0E–07
8.0E–07
8.0E–07
8.0E–07
8.0E–07
8.0E–07
4.8E–07
4.8E–07
4.8E–07
7.9E–06
CO
(ppm @3%
oxygen) a
Alternate CO
CEMS limit,
(ppm @3%
oxygen) b
160
130
140
130
1,500
460
470
2,400
770
1,100
2,800
130
130
130
130
130
130
140
130
620
460
230
2,400
330
910
1,100
130
130
130
130
340
230
150
320
720
ND
310
c 2,000
c 520
ND
900
ND
ND
ND
ND
340
230
150
320
390
ND
310
c 2,000
c 520
ND
900
ND
ND
ND
ND
NA-Not applicable; ND-No data available
a 3-run average, unless otherwise noted.
b 30-day rolling average, unless otherwise noted.
c 10-day rolling average.
tkelley on DSK3SPTVN1PROD with
We also are finalizing a work practice
standard for dioxin/furan emissions
from all subcategories.
D. What are the requirements during
periods of startup and shutdown?
We are finalizing revised work
practice standards for periods of startup
and shutdown to better reflect the
maximum achievable control
technology during those periods. In
addition, we are finalizing definitions of
startup and shutdown. We are defining
startup as the period between the state
of first-firing of fuel in the unit after a
shutdown to the period where the unit
first supplies steam. We are defining
shutdown as the period that begins
when no more steam is supplied or at
the point of no fuel being fired in the
unit. For periods of startup and
shutdown, we are finalizing the
following work practice standard: You
must operate all continuous monitoring
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systems during startup and shutdown.
For startup, you must use one or a
combination of the listed clean fuels.
Once you start firing coal/solid fossil
fuel, biomass/bio-based solids, heavy
liquid fuel, or gas 2 (other) gases, you
must engage all of the applicable control
devices except limestone injection in
FBC boilers, dry scrubber, fabric filter,
SNCR and SCR. You must start your
limestone injection in FBC boilers, dry
scrubber, fabric filter, SNCR and SCR
systems as expeditiously as possible.
During shutdown while firing coal/solid
fossil fuel, biomass/bio-based solids,
heavy liquid fuel, or gas 2 (other) gases
during shutdown, you must operate all
applicable control devices, except
limestone injection in FBC boilers, dry
scrubber, fabric filter, SNCR and SCR.
You must comply with all applicable
emissions and operating limits at all
times the unit is in operation except for
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periods that meet the definitions of
startup and shutdown in this subpart,
during which times you must comply
with these work practices. You must
keep records during periods of startup
or shutdown. You must keep records
concerning the date, duration, and fuel
usage during startup and shutdown.
E. What are the testing and initial
compliance requirements?
We are requiring that the owner or
operator of a new or existing boiler or
process heater conduct performance
tests to demonstrate compliance with all
applicable emission limits. This final
rule adds the requirement to conduct
initial and annual stack tests to
determine compliance with the TSM
emission limits using EPA Method 29
for those subcategories with alternate
TSM limits.
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F. What are the continuous compliance
requirements?
This final rule removes the
requirement for units combusting
biomass with heat input capacities of
250 MMBtu/hr or greater to install,
certify, maintain and operate a CEMS
measuring PM emissions. This final rule
requires units combusting solid fossil
fuel or heavy liquid with heat input
capacities of 250 MMBtu/hr or greater to
install, certify, maintain, and operate
PM CPMS. Moreover, owners or
operators of units combusting solid
fossil fuel or heavy liquid with heat
input capacities of 250 MMBtu/hr or
greater are allowed to install, certify,
maintain and operate PM CEMS as an
alternative to the use of PM CPMS,
consistent with regulations for
similarly-sized commercial and
industrial solid waste incinerators units
and EGUs subject to the MATS. Just as
units using PM CPMS will not be
required to conduct parameter
monitoring for PM, units using PM
CEMS will not be required to conduct
parameter monitoring for PM.
This final rule also includes an
alternative method of demonstrating
continuous compliance with the HCl
emission limit. This method allows
using SO2 emissions as an alternate
operating limit. This method of
demonstrating continuous compliance
will be allowed only on a unit that
utilizes a SO2 CEMS and an acid-gas
control technology including wet
scrubber, dry scrubbers and duct
sorbent injection. Boilers or process
heaters subject to an HCl emission limit
that demonstrate compliance with an
SO2 CEMS would be required to
maintain the 30-day rolling average SO2
emission rate at or below the highest
hourly average SO2 concentration
measured during the most recent HCl
performance test.
tkelley on DSK3SPTVN1PROD with
G. What are the compliance dates?
For existing sources, the EPA is
establishing a compliance date of
January 31, 2016. New sources must
comply by January 31, 2013, or upon
startup, whichever is later. New sources
are defined as sources which
commenced construction or
reconstruction on or after June 4, 2010
pursuant to section 112(a)(4).
Commenters have argued that the 3year compliance deadline the EPA is
establishing for existing sources to meet
the standards does not provide them
with sufficient time to meet the
standards in view of the large number
of sources that will be competing for the
needed resources and materials from
engineering consultants, permitting
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authorities, equipment vendors,
construction contractors, financial
institutions, and other critical suppliers.
As an initial matter, we note that
many sources subject to the emission
standards in the final rule should be
able to meet the standards within three
years, even those that need to install
pollution control technologies to do so.
In addition, many sources subject to the
rule are gas fired units or small boilers
(less than 10 MMBtu/hr) and will not
need to install controls in order to
demonstrate compliance, as these
sources are subject to work practice
standards. For these sources, the 3-year
compliance deadline is highly unlikely
to be problematic either in general, or
with respect to the claims commenters
have made about the possibility that the
demand for resources related to control
technology will exceed the supply.
At the same time, the CAA allows title
V permitting authorities to grant
sources, on a case-by-case basis,
extensions to the compliance time of up
to one year if such time is needed for
the installation of controls. See CAA
section 112(i)(4)(i)(A). Permitting
authorities are already familiar with,
and in many cases have experience
with, applying the 1-year extension
authority under section 112(i)(4)(A)
since the provision applies to all
NESHAP. We believe that should the
range of circumstances that commenters
have cited as impeding sources’ ability
to install controls within three years
materialize, then it is reasonable for
permitting authorities to take those
circumstances into consideration when
evaluating a source’s request for a 1-year
extension, and where such applications
prove to be well-founded, it is also
reasonable for permitting authorities to
make the 1-year extension available to
applicants.
In making a determination as to
whether an extension is appropriate, we
believe it is also reasonable for
permitting authorities to consider the
large number of pollution control
retrofit projects being undertaken for
purposes of complying either with the
standards in this rule or with those of
other rules such as MATS for the power
sector that may be competing for similar
resources.
Further, commenters have pointed out
that in some cases operators of existing
sources that are subject to these
standards and that generate energy may
opt to meet the standards by terminating
operations at these sources and building
new sources to replace the energy
generation at the shut-down sources.
While the ultimate discretion to provide
a 1-year extension lies with the
permitting authority, the EPA believes
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7143
that it is reasonable for permitting
authorities to allow the fourth year
extension for the installation of
replacement sources of energy
generation at the site of a facility
applying for an extension for that
purpose. Specifically, the EPA believes
where an applicant demonstrates that it
is building replacement sources of
energy generation for purposes of
meeting the requirements of these
standards such a replacement project
could be deemed to constitute the
‘‘installation of controls’’ under section
112(i)(3)(B).
In a case where pollution controls are
being installed or onsite replacement
energy generation is being constructed
to allow for retirement of older, undercontrolled energy generation units, a
determination that an extra year is
necessary for compliance should be
relatively straightforward. In order to
install controls, companies are likely to
undertake a number of steps relatively
soon after the effective date of the rule,
including obtaining necessary building
and environmental permits and hiring
contractors to perform the construction
of the emission controls or replacement
energy generation units. This should
provide sufficient information for a
permitting authority to determine that
emission controls are being installed or
that replacement energy generation is
being constructed. As a result, a
permitting authority will be in a
position to make a determination as to
whether a source’s compliance schedule
will exceed 3 years and to quickly make
a determination as to when an extension
is appropriate.
In sum, the EPA believes that
although most, if not all, units will be
able to fully comply with the standards
within 3 years, the fourth year that
permitting authorities are allowed to
grant for installation of controls is an
important flexibility that will address
situations where an extra year is
necessary. Of course in situations where
EPA is the permitting authority, we
would also consider the above
circumstances when acting on a permit
application.
IV. Summary of Significant Changes
Since Proposal
The EPA has made numerous changes
in this final rule from the proposal after
consideration of the public comments
received. Most are changes to clarify
applicability and implementation issues
raised by the commenters. The public
comments received on the proposed
changes and the responses to them can
be viewed in the memorandum
‘‘Response to Comments for Industrial,
Commercial, and Institutional Boilers
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and Process Heaters National Emission
Standards for Hazardous Air Pollutants’’
located in the docket.
tkelley on DSK3SPTVN1PROD with
A. Applicability
Since proposal, the EPA has made
certain changes to the applicability of
this final rule. We have clarified that the
exemption for boilers and process
heaters used for research and
development includes boilers used for
testing the propulsion systems on
military vessels. This is consistent with
the intent of the exemption in that these
test boilers do not provide steam for
heating, to a process, or other nonpropulsion related uses but are used
exclusively to test the propulsion
systems of nuclear-powered aircraft
carriers that are undergoing repair,
overhaul, or installation.
B. Subcategories
As described in the preamble to the
proposed reconsideration rule, within
the basic unit types of boilers and
process heaters there are different
designs and combustion systems that,
while having a minor effect on fueldependent HAP emissions, have a much
larger effect on pollutants whose
emissions depend on the combustion
conditions in a boiler or process heater.
In the case of boilers and process
heaters, the combustion-related
pollutants are the organic HAP. In the
proposed rule, we identified the
following 17 subcategories for organic
HAP: (1) Pulverized coal units; (2)
stokers designed to burn coal; (3)
fluidized bed units designed to burn
coal; (4) stokers designed to burn wet
biomass; (5) stokers designed to burn
kiln-dried biomass; (6) fluidized bed
units designed to burn biomass; (7)
suspension burners designed to burn
biomass; (8) dutch ovens/pile burners
designed to burn biomass; (9) fuel cells
designed to burn biomass; (10) hybrid
suspension grate units designed to burn
biomass; (11) units designed to burn
heavy liquid fuel; (12) units designed to
burn light liquid fuel; (13) noncontinental liquid units; (14) units
designed to burn natural gas/refinery
gas; (15) units designed to burn other
gases; (16) metal process furnaces; and
(17) limited-use units.
In this final rule, we are also adding
a separate subcategory for fluidized bed
units with a fluidized bed heat
exchanger designed to burn coal and
adjusted the definition of the limited
use subcategory.
Fluidized bed boilers are designed to
combust fuel with relatively low heating
value and high ash compared to other
combustor designs. Two fuel properties
of coal are heating values and ash
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content. As the heating value of the coal
decreases, ash content increases.
Fluidized bed boilers are designed to
have large tube surface areas to transfer
heat from the fuel through the process
of conduction and convection, but in
some cases the amount of tube surface
area in the furnace for heat transfer is
insufficient. In order to overcome
insufficient heat exchange, certain
fluidized bed boilers adopt a fluidized
bed heat exchanger design to achieve
heat transfer. The fluidized bed heat
exchanger is located at the exit of the
cyclone section of the unit. This design
allows the boiler to combust coal with
a lower heating value than a coal-fired
fluidized bed boiler without a fluidized
bed heat exchanger. Therefore, because
this boiler design does have different
combustion-related HAP emission
characteristics, a new subcategory of
coal fluidized bed with integrated heat
exchanger was added to the final rule.
The EPA is also revising the
definition of the limited use
subcategory. Many affected units
operate on standby mode or low loads
for periods longer than the proposed
definition for limited use units, which
limited operation to 876 hours per year.
By converting to a capacity-factor
approach, we are allowing more
flexibility on unit operations without
increasing emissions or harm to human
health and the environment. For
example, units operating at 10 percent
load for 8,760 hours per year would
emit the same amount of emissions as
units operating at full load for 876 hours
per year. Further, it is technically
infeasible to schedule stack testing for
these limited use units since these units
serve as back up energy sources and
their operating schedules can be
intermittent and unpredictable. The
limited use subcategory was adjusted to
be based on units with a federally
enforceable operating limit of less than
or equal to 10 percent of an average
annual capacity factor.
C. Performance Test Requirements
Table 5 of this final rule has been
revised to add performance test
procedures for conducting performance
stack tests for demonstrating
compliance with the alternate TSM
emission limits. In the reconsideration
proposal, we proposed emissions limits
for TSM (i.e., arsenic, beryllium,
cadmium, chromium, lead, manganese,
nickel and selenium) as an alternative to
the proposed PM emission limits for
many of the subcategories. In the
preamble to the proposed rule, we
added procedures in Table 6 of the rule
for conducting fuel analysis for total
selected metals but we inadvertently
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failed to add performance test
requirements for stack sampling of TSM
emissions in Table 5 of the rule.
D. Emission Limits
One significant change since proposal
is related to the PM emission limits for
the coal subcategories. Several
petitioners disagreed with EPA’s
position to set different PM limits for
subcategories of boilers and process
heaters based on the fuel used, and
instead offered information to support
the position that PM should be
considered a combustion-based
pollutant. The differences in PM
particle size, fouling characteristics and
feasibility of certain control
technologies on certain unit designs
suggested that PM is more appropriately
classified as a combustion-based
pollutant, but only for the coal
subcategories. After assessing the points
raised by the petitioners, the EPA agreed
that PM emissions are influenced by
unit design, and fuel type, and proposed
to create combustion-based pollutant
subcategories for coal and solid fuels
and create fuel-based subcategories for
liquid and biomass fuel units. The EPA
is finalizing a single PM limit for all
coal/solid fossil fuel subcategories, and
is also finalizing emissions limits based
on PM as a combustion-based pollutant
for the biomass and liquid fuel
subcategories.
Another change from proposal is that
the alternative TSM emission limits are
now applicable to the three liquid fuel
subcategories. Several commenters
provided data and comments supporting
these alternative emission standards for
non-mercury metallic HAP. After
assessing the revised data and the points
made by the commenters, the EPA
agrees that the limited data available for
liquid fuel units are not unique to this
subcategory. Based on the EPA agreeing
with the commenters, the EPA recalculated the TSM emission limits for
the liquid fuel subcategories and
included them in the final rule.
The CO emission limit for several
subcategories, both new and existing,
have been revised to reflect a CO level
that is consistent with MACT for
organic HAP reduction. Several
commenters recommended that the EPA
evaluate a minimum CO standard (i.e.,
100 ppm corrected to 7 percent oxygen)
to serve as a lower bound surrogate for
organic HAP. Commenters also
provided data and information to
support such a standard, and noted that
the EPA has taken a similar approach in
other emission standards under section
112.
The EPA evaluated whether there is a
minimum CO level for boilers and
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Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
process heaters below which there is no
further benefit in organic HAP
reduction/destruction. Specifically, we
evaluated the relationship between CO
and formaldehyde using the available
data obtained during the rulemaking.
Formaldehyde was selected as the basis
of the organic HAP comparison because
it is the most prevalent organic HAP in
the emission database and a large
number of paired tests existed for
boilers and process heaters for CO and
formaldehyde. The paired data show
decreasing formaldehyde emissions
with decreasing CO emissions down to
CO levels around 300 ppm, supporting
the selection of CO as a surrogate for
organic HAP emissions. A slight
increase in formaldehyde emissions is
observed at CO levels below around 200
ppm, suggesting a breakdown in the COformaldehyde relationship at low CO
levels. At levels lower than 150 ppm,
the mean levels of formaldehyde appear
to increase, as does the overall
maximum value of and variability in
formaldehyde emissions. However, we
are aware of no reason why CO
concentrations would continue to
decrease and formaldehyde
concentrations would increase as
combustion conditions improve. It is
possible that imprecise formaldehyde
measurements at low concentrations
(i.e., 1–2 ppm) may account for this
slight increase in formaldehyde
emissions observed at CO levels below
100 ppm corrected to 7 percent oxygen.
Based on this, we do not believe that
such measurements are sufficiently
reliable to use as a basis for establishing
an emissions limit.
Therefore, based on the above
analysis, we are promulgating a
minimum MACT floor level for CO of
130 ppm corrected to 3 percent oxygen
(which is equivalent to 100 ppm
corrected to 7 percent oxygen). We note
this is the same approach used to
establish the CO emission limit of 100
ppm corrected to 7 percent oxygen for
the Burning of Hazardous Waste in
Boilers and Industrial Furnaces rule.
Additional discussion of the rationale
for this approach can be found in the
memorandum ‘‘Revised MACT Floor
Analysis (August 2012) for Industrial,
Commercial, Institutional Boilers and
Process Heaters National Emission
Standards for Hazardous Air
Pollutants—Major Source.’’
Subcategories where the initial MACT
floor 99 percent UPL calculations for CO
were less than 100 ppm corrected to 7
percent oxygen (or equivalently 130
ppm corrected to 3 percent oxygen) are
as follows:
• New and Existing Subcategories:
Coal-FB, Coal-PC, Heavy Liquid, Light
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Liquid, Non-Continental Liquid, Process
Gas
• New Subcategories: Coal-Stoker
We believe a CO level of 130 ppm
corrected to 3 percent oxygen is an
appropriate minimum MACT floor
level. Although some measurements
show CO levels below 130 ppm
corrected to 3 percent oxygen, it is not
appropriate to establish a lower floor
level because CO is a conservative
surrogate for organic HAP. In other
words, organic HAP emissions are
extremely low when sources operate
under the good combustion conditions
required to achieve CO levels in the
range of zero to 100 ppm. As such,
lowering the CO floor below 100 ppm
will not provide reductions in organic
HAP emissions. There are myriad
factors that affect combustion efficiency
and, as a function of combustion
efficiency, CO emissions. As
combustion conditions improve and
hydrocarbon levels decrease, the larger
and easier to combust compounds are
oxidized to form smaller compounds
that are, in turn, oxidized to form CO
and water. As combustion continues,
CO is then oxidized to form carbon
dioxide and water. Because CO is a
difficult to destroy refractory compound
(i.e., oxidation of CO to carbon dioxide
is the slowest and last step in the
oxidation of hydrocarbons), it is a
conservative surrogate for destruction of
hydrocarbons, including organic HAP.
The conservative nature of CO as an
indicator of good combustion practices
is supported by our data. At CO levels
less than 100 ppm corrected to 7 percent
oxygen, our data indicate that there is
no apparent relationship between CO
and organic HAP (i.e., formaldehyde).
For example, a source with a CO level
of 20 ppm may have the same measured
formaldehyde as a source achieving a
CO emission level of 100 ppm corrected
to 7 percent oxygen. Sources are
required to establish operating
requirements based on operating levels
that were demonstrated during the test.
Sources must comply with these
operating requirements on a continuous
basis. Compliance with these
requirements adequately assures sources
will be controlling organic HAP
emissions to MACT levels.
As detailed in the docketed
memorandum ‘‘Beyond the Floor
Technology Analysis for Major Source
Boilers and Process Heaters (Revised
August 2012),’’ we reviewed the
emission limits that are becoming less
stringent since the March 2011 final rule
in order to assess whether a beyond the
floor option was technically achievable
and cost effective. As a result of this
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7145
review, the PM emission limits for
several new biomass subcategories have
been changed to reflect a beyond the
floor limit of 0.03 lb/MMBtu, based on
the limit for new biomass boilers in 40
CFR part 60 subparts Db and Dc. Due to
the low mercury emission limits for new
solid fuel boilers, these new biomass
units are expected to install a fabric
filter level of control in order to meet
the new source mercury limits for the
solid fuel subcategory. This mercury
control has the co-benefit of reducing
PM emissions down to levels of 0.03 lb/
MMBtu so there is no incremental cost
to achieve these additional reductions
in PM for the biomass units that have a
design heat input capacity between 10
and 30 MMBtu/hr. For units with a
design heat input capacity of 30
MMBtu/hr or greater, these units are
already subject to a PM limit of 0.03 lb/
MMBtu and adjusting these new source
limits to this level of control makes the
limits consistent between both rules,
without adding additional costs. We did
not identify any beyond the floor
options for existing source PM limits or
new and existing limits for other
pollutants as technically feasible or cost
effective.
The other changes associated with the
other emission limits are due to new
data, corrections to old data, and
inventory changes. In summary,
compared to the December 23, 2011
proposed limits for existing units, the
final HCl emission limits remained the
same; for the final mercury emission
limits, 3 are more stringent, 10 are less
stringent and 1 is unchanged; for the
final PM emission limits, 3 are more
stringent, 5 are less stringent and 6 are
unchanged; and for the final CO
emission limits, 3 are more stringent
and 11 are less stringent. For new units,
compared to the proposed emission
limits, 3 of the final HCl emission limits
are more stringent and 11 remained the
same; for the final mercury emission
limits, 10 are more stringent and 4 are
unchanged; for the final PM emission
limits, 5 are more stringent, 2 are less
stringent and 7 are unchanged; and for
the final CO emission limits, 2 are more
stringent, 11 are less stringent and 1 is
unchanged.
E. Work Practice Requirement
In this final rule several changes have
been made to the work practice
requirement to conduct a tune-up. First,
the requirement to inspect the burner
has been revised to allow units that sell
electricity to schedule the burner
inspection, as well as the air-to-fuel
system inspection, at the time of the
first outage but not to exceed 36 months
from the previous inspection. This
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change is being made to this final rule
because commenters stated that large
boilers that serve electricity for sale may
not require annual outages and would,
therefore, need to be taken off-line for
the sole purpose of an annual tune-up.
This frequency is consistent with the
requirements of the NESHAP for electric
utility boilers (40 CFR part 63, subpart
UUUUU).
Also, for units where entry into a
piece of process equipment or into a
storage vessel is required to complete
the tune-up inspections, inspections are
required only during planned entries
into the storage vessel or into process
equipment. Commenters indicated that
some process heaters are installed
inside tanks and entry into the tank to
access the heater may not occur within
a 5 year period.
The requirement to optimize total
emissions of CO has been revised to
require that this optimization not only
be consistent with the manufacturer’s
specifications but also with any NOX
emission requirement to which the unit
is subject. Some commenters indicated
that many boilers need different tune-up
criteria due to their requirement to also
comply with low NOX emission limits.
We are also aware that several states
have boiler tune-up requirements to
minimize NOX emissions first and then
optimize CO emissions.
We have added boilers or process
heaters that have a continuous oxygen
trim system to the types of boilers or
process heaters that must conduct a
tune-up every 5 years. These units do
not need to be tuned as frequently
because the trim system is designed to
continuously measure and maintain an
optimum air to fuel ratio which is the
purpose of a tune-up.
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F. Averaging Times Definitions
We revised the definitions of ‘‘30-day
rolling average’’ and ‘‘daily block
average’’ to exclude periods of startup
and shutdown or downtime from the
arithmetic mean. Commenters requested
that the EPA specify how a 30-day
rolling average is calculated and
whether it includes the previous 720
hours of valid operating data and that
the valid data exclude hours during
startup and shutdown as well as unit
down time. We agree with the
commenters that the definitions need
clarification and that these periods
should not be included in calculating
the 30-day rolling average. Therefore,
we have revised the definitions
accordingly.
We have also included in the final
rule a definition of ‘‘10-day rolling
average’’ that is consistent with the
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revised definition of ‘‘30-day rolling
average.’’
G. Energy Assessment
In this final rule, we have revised the
definition of energy assessment per the
requirements of Table 3 of this final rule
by providing duration for performing
the energy assessment for large fuel use
facilities. In numbered paragraph (3) in
the definition of ‘‘Energy assessment’’ in
§ 63.7575, which is for facilities with
units having a combined heat input
capacity greater than 1 TBtu/yr, we
added time duration/size ratio and
included a cap to the maximum number
of on-site technical hours that should be
used in the energy assessment. This
addition of a duration for large fuel use
facilities is being made to be consistent
with durations specified for small
[paragraph (1) in the definition of
‘‘Energy assessment’’] and medium
[paragraph (2) in the definition of
‘‘Energy assessment’’] fuel use facilities.
The energy assessment for facilities with
affected boilers and process heaters
having a combined heat input capacity
greater than 1.0 TBtu/yr will be up to 24
on-site technical labor hours for the first
TBtu/yr plus 8 technical labor hours for
every additional 1.0 TBtu/yr not to
exceed 160 technical hours, but may be
longer at the discretion of the owner or
operator.
The revised definition of energy
assessment also clarifies our intentions
that the scope of assessment is based on
energy use by discrete segments of a
facility and not by a total aggregation of
all individual energy using elements of
a facility. The applicable discrete
segments of a facility could vary
significantly depending on the site and
its complexity. We have added the
following paragraph (4), to the energy
assessment definition to help resolve
current problems in identifying the
scope of the various energy use systems
in a large industrial complex and allow
for more streamlined assessments:
‘‘(4) The on-site energy use systems
serving as the basis for the percent of
affected boiler(s) and process heater(s)
energy output in (1), (2) and (3) above
may be segmented by production area or
energy use area as most logical and
applicable to the specific facility being
assessed (e.g., product X manufacturing
area; product Y drying area; Building
Z).’’
We have also revised paragraph 4 of
Table 3 of the final rule to allow a
source that is operating under an energy
management program established
through energy management systems
compatible with ISO 50001, which
includes the affected units, to satisfy the
energy assessment requirement. We
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consider these energy management
programs to be equivalent to the onetime energy assessment because
facilities having these programs operate
under a set of practices and procedures
designed to manage energy use on an
ongoing basis. These programs contain
energy performance measurements and
tracking plans with periodic reviews.
The definition of ‘‘Energy use system’’
has also been revised in this final rule
to clarify that energy use systems are
only those systems using energy clearly
produced by affected boilers and
process heaters.
H. Startup and Shutdown Definitions
A number of commenters indicated
that the proposed load specifications
(i.e., 25 percent load) within the
definitions of ‘‘startup’’ and
‘‘shutdown’’ were inconsistent with
either safe or normal (proper) operation
of the various types of boilers and
process heaters encountered within the
source category. As the basis for
defining periods of startup and
shutdown, a number of commenters
suggested alternative load specifications
based on the specific considerations of
their boilers; other commenters
suggested the achievement of various
steady-state conditions.
We have reviewed these comments
and believe adjustments are appropriate
in the definition of ‘‘startup’’ and
‘‘shutdown.’’ These adjustments are
tailored for industrial boilers and are
consistent with the definitions of
‘‘startup’’ and ‘‘shutdown’’ contained in
the 40 CFR part 63, subpart A General
Provisions. We believe these revised
definitions address the comments and
are rational based on the fact that
industrial boilers function to provide
steam or, in the case of cogeneration
units, electricity; therefore, industrial
boilers should be considered to be
operating normally at all times steam of
the proper pressure, temperature, and
flow rate is being supplied to a common
header system or energy user(s) for use
as either process steam or for the
cogeneration of electricity. The
definitions of ‘‘startup’’ and
‘‘shutdown’’ have been revised in the
final rule as follows:
‘‘Startup means either the first-ever
firing of fuel in a boiler or process
heater for the purpose of supplying
steam or heat for heating and/or
producing electricity, or for any other
purpose, or the firing of fuel in a boiler
or process heater after a shutdown event
for any purpose. Startup ends when any
of the steam or heat from the boiler or
process heater is supplied for heating
and/or producing electricity, or for any
other purpose.’’
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‘‘Shutdown means the cessation of
operation of a boiler or process heater
for any purpose. Shutdown begins
either when none of the steam and heat
from the boiler or process heater is
supplied for heating and/or producing
electricity, or for any other purpose, or
at the point of no fuel being fired in the
boiler or process heater, whichever is
earlier. Shutdown ends when there is
both no steam or heat being supplied
and no fuel being fired in the boiler or
process heater.’’
The EPA is requiring sources to vent
emissions to the main stack(s) and
operate all control devices necessary to
meet the normal operating standards
under this final rule (with the exception
of limestone injection in FBC boilers,
dry scrubber, fabric filter, SNCR and
SCR) when firing coal/solid fossil fuel,
biomass/bio-based solids, heavy liquid
fuel or gas 2 (other) gases in the boiler
or process heater during startup or
shutdown. It is the responsibility of the
operators of affected boilers and process
heaters to start their limestone injection
in FBC boilers, dry scrubber, fabric
filter, SNCR and SCR systems
appropriately to comply with relevant
standards applicable during normal
operation. Startup ends and normal
operating standards apply when heat or
steam is supplied for any purpose.
The EPA carefully considered fuels
and potential operational constraints of
APCD when designing its work
practices for periods of startup and
shutdown. The EPA notes that there is
no technical barrier to burning clean
fuels (e.g., natural gas, distillate oil) for
longer portions of startup or shutdown
periods at a boiler and the HAP
emission reduction benefits warrant
additional utilization of such fuels until
the temperature and stack emissions
pressure is sufficient to engage the
APCD. The EPA is aware that SNCR and
SCR systems with ammonia injection
need to be operated within a prescribed
and relatively narrow temperature
window to provide NOX reductions.
Further, the EPA is aware that dry
scrubbers also need to be operated close
to flue gas saturation temperature, and
that fabric filters need to be operated at
temperatures above the acid dew point.
Because these devices have specific
temperature requirements for proper
operation, the EPA notes in its work
practices that it is the responsibility of
the operators of affected boilers and
process heaters to start their SNCR, SCR,
fabric filter and dry scrubber systems
appropriately to comply with relevant
standards applicable during normal
operation.
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I. Fuel Sampling Frequency
The sampling frequency for gaseous
fuel-fired units that elected to
demonstrate that the unit meets the
specification for mercury for the unit
designed to burn gas 1 subcategory has
been revised in this final rule. If the
initial mercury constituents in the
gaseous fuels are measured to be equal
to or less than half of the mercury
specification, no further sampling is
required. If the initial mercury
constituents are greater than half but
equal to or less than 75 percent of the
mercury specification, only semi-annual
sampling need to be conducted. If the
initial mercury constituents are greater
than 75 percent of the mercury
specification, monthly sampling is
required.
J. Affirmative Defense
In the proposal, we used terms such
as ‘‘exceedance’’ or ‘‘excess emissions’’
in § 63.7501, which created unnecessary
confusion as to when the affirmative
defense could be used. In the final
amended rule, we have eliminated those
terms and used the word ‘‘violation’’ to
make clear that the affirmative defense
to civil penalties is available only where
an event that causes a violation of the
emissions standard meets the definition
of malfunction under § 63.2.
We have also eliminated the 2-day
notification requirement that was
included in 40 CFR 63.7501(b) at
proposal because we expect to receive
sufficient notification of malfunction
events that result in violations in other
required compliance reports, such as the
malfunction report required under 40
CFR 63.7550(c). In addition, we have
revised the 45-day affirmative defense
reporting requirement that was included
in 40 CFR 63.7501(b) at proposal to
require sources to include the report in
the first compliance, deviation or excess
emission report due after the initial
occurrence of the violation, unless the
compliance, deviation or excess
emission report is due less than 45 days
after the violation. In that case, the
affirmative defense report may be
included in the second compliance,
deviation or excess emission report due
after the initial occurrence of the
violation. Because the affirmative
defense report is now included in a
subsequent compliance, deviation or
excess emission report, there is no
longer a need for the proposed 30-day
extension for submitting a stand-alone
affirmative defense report.
Consequently, we are not including this
provision in the final amended rule. We
have also re-evaluated the language
concerning the use of off-shift and
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overtime labor to the extent practicable
and believe that the language is not
necessary. Thus, we have deleted that
phrase from section 63.7501(a)(2).
V. Other Actions We Are Taking
Section 307(d)(7)(B) of the CAA states
that ‘‘[o]nly an objection to a rule or
procedure which was raised with
reasonable specificity during the period
for public comment (including any
public hearing) may be raised during
judicial review. If the person raising an
objection can demonstrate to the
Administrator that it was impracticable
to raise such objection within such time
or if the grounds for such objection
arose after the period for public
comment (but within the time specified
for judicial review) and if such objection
is of central relevance to the outcome of
the rule, the Administrator shall
convene a proceeding for
reconsideration of the rule and provide
the same procedural rights as would
have been afforded had the information
been available at the time the rule was
proposed. If the Administrator refuses to
convene such a proceeding, such person
may seek review of such refusal in the
United States court of appeals for the
appropriate circuit (as provided in
subsection (b)).’’
As to the first procedural criterion for
reconsideration, a petitioner must show
why the issue could not have been
presented during the comment period,
either because it was impracticable to
raise the issue during that time or
because the grounds for the issue arose
after the period for public comment (but
within 60 days of publication of the
final action). The EPA is denying the
petitions for reconsideration on a
number of issues because this criterion
has not been met. In many cases, the
petitions reiterate comments made on
the proposed June 2011 rule during the
public comment period for that rule. On
those issues, the EPA responded to
those comments in the final rule and
made appropriate revisions to the
proposed rule after consideration of
public comments received. It is wellestablished that an agency may refine its
proposed approach without providing
an additional opportunity for public
comment. See Community Nutrition
Institute v. Block, 749 F.2d at 58 and
International Fabricare Institute v. EPA,
972 F.2d 384, 399 (D.C. Cir. 1992)
(notice and comment is not intended to
result in ‘‘interminable back-andforth[,]’’ nor is agency required to
provide additional opportunity to
comment on its response to comments)
and Small Refiner Lead Phase-Down
Task Force v. EPA, 705 F.2d 506, 547
(D.C. Cir. 1983) (‘‘notice requirement
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should not force an agency endlessly to
repropose a rule because of minor
changes’’)
In the EPA’s view, an objection is of
central relevance to the outcome of the
rule only if it provides substantial
support for the argument that the
promulgated regulation should be
revised. See Union Oil v. EPA, 821 F.2d
768, 683 (D.C. Cir. 1987) (court declined
to remand rule because petitioners
failed to show substantial likelihood
that final rule would have been changed
based on information in petition). See
also the EPA’s Denial of the Petitions to
Reconsider the Endangerment and
Cause or Contribute Findings for
Greenhouse Gases under Section 202 of
the Clean Air Act, 75 FR at 49556, 49561
(August 13, 2010). See also, 75 FR at
49556, 49560–49563 (August 13, 2010)
and 76 FR at 4780, 4786–4788 (January
26, 2011) for additional discussion of
the standard for reconsideration under
CAA section 307(d)(7)(B).
We are denying reconsideration on
the following 57 issues contained in the
petitions for reconsideration because
they failed to meet the standard
described above for reconsideration
under CAA section 307(d)(7)(B).
Specifically, on these issues, the
petitioner has failed to show the
following: that it was impracticable to
raise their objections during the
comment period or that the grounds for
their objections arose after the close of
the comment period; and/or that their
concern is of central relevance to the
outcome of the rule. Therefore, the EPA
is denying the petitions for
reconsideration on the issues for the
reasons described below.
Issue: Delist gas units.
The petitioners (API, NPRA)
requested that the EPA remove gas-fired
units from the section 112(c) list of
source categories for which the EPA is
required to establish emissions
standards under section 112(d). The
EPA is denying the petition for
reconsideration for the following
reasons. First, the issue is outside the
scope of this rulemaking, which
establishes emissions standards for new
and existing units within the major
source boilers and process heaters
source category. The EPA did not solicit
comment in the proposed rule regarding
the scope of the subcategory. Further,
petitioners provide no information to
support delisting gas units under
section 112(c)(9), which requires the
EPA to make certain findings before
delisting any sources. In addition, the
petition does not address the D.C.
Circuit’s decision in NRDC v. EPA, 489
F.3d 1364 (2007), regarding the EPA’s
ability to delist subcategories of a source
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category pursuant to section 112(c)(9).
For these reasons, the petitions do not
provide support for the argument that
the regulation should be changed. For
this reason, the petition does not
demonstrate that the issue is of central
relevance to the outcome of the final
rule and the EPA is denying the request
for reconsideration.
Issue: Exempt natural gas hot water
heaters with tanks greater than 120
gallons.
The petitioner (AIF) requested that
the EPA exempt natural gas hot water
heaters with tanks greater than 120
gallons. While the EPA disagrees with
the petitioner regarding whether such
units should be subject to the emissions
standards in this rule, the petitioner has
not demonstrated that it lacked the
opportunity to comment on whether
such units should be required to meet
emissions standards. The EPA proposed
work practice standards for such units
in its June 2010 proposal, and the
petitioner had the opportunity to
comment on whether such standards
should be applied to such units at all.
Therefore, the EPA is denying the
request for reconsideration.
Issue: Exempt natural gas and
distillate oil-fired circulating hot water
systems with a design capacity of 10
MMBtu/hr or less.
The petitioner (CIBO) requested that
the EPA exempt natural gas and
distillate oil-fired circulation hot water
systems that are not greater than 10
MMBtu/hr. While the EPA disagrees
with the petitioner regarding whether
such units should be subject to the
emissions standards in this rule, the
petitioner has not demonstrated that it
lacked the opportunity to comment on
whether such units should be required
to meet emissions standards. The EPA
proposed emissions standards for such
units, and the petitioner had the
opportunity to comment on whether
such standards should be applied to
such units at all. In addition, the
petition does not provide any
information to demonstrate that these
units should be delisted pursuant to
section 112(c)(9). Therefore, the EPA is
denying the request for reconsideration.
Issue: Confirm in definitions that
open flame heaters (e.g., asphalt tank
heaters) are not process heaters.
The petitioners (API, NPRA)
requested that the EPA clarify in the
definition of ‘‘process heater’’ that open
flame heaters do not meet the definition.
While the EPA disagrees with the
petitioners whether clarification is
needed in regards to open flame heaters,
the petitioners have not demonstrated
that it lacked the opportunity to
comment on the proposed definition.
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The definition that the EPA proposed
clearly states that process heaters are
enclosed devices in which the
combustion gases do not come into
contact with process materials, and as
such, does not include open flame
heaters. Therefore, the EPA is denying
reconsideration.
Issue: For blast furnace fuel-fired
boiler exemption, compute the 90
percent BFG by volume threshold to
exclude periods of BFG curtailment.
The petitioners (AISI, ACCCI)
requested that the EPA revise the
exemption for BFG fuel-fired boilers to
exclude periods of BFG curtailment.
While the EPA disagrees with the
petitioners regarding revising the
exemption, the petitioners have not
demonstrated that it lacked the
opportunity to comment on the
proposed exemption for BFG fuel-fired
boilers. The EPA proposed the
exemption for these boilers, and
petitioners therefore had the
opportunity to comment on whether the
exemption should apply to periods of
BFG curtailment. Therefore, the EPA is
denying the request for reconsideration.
Issue: Exempt boilers whose flue gases
are used in direct-fired process heaters
subject to other NESHAP.
The petitioner (CMI) requested that
the EPA exempt from the rule boilers
whose flue gases are used in direct-fired
process heaters that are subject to other
NESHAP. The final rule does not apply
to such units if they are subject to
another NESHAP. The EPA does not see
a need for further clarification. Since the
final rule does in fact exempt these
units, the EPA is denying the request for
reconsideration.
Issue: Work practice standards do not
meet EPA obligations under 112(c)(6).
The petitioner (Sierra Club) requested
that the EPA establish numeric
emissions limits for Gas 1 units rather
than work practice standards.
Specifically, the petitioner alleges that
the work practice standards do not meet
the EPA’s obligations under section
112(c)(6) of the CAA, and that it was not
the case that data were below the
detection level for all HAP emitted from
these units. The EPA is denying the
request for reconsideration on this issue.
While the EPA disagrees with the
petitioner’s arguments regarding the
legal authority to establish work
practice standards for Gas 1 units and
the basis for such standards, the
petitioner has not demonstrated that it
lacked the opportunity to comment on
this issue. The EPA proposed work
practice standards for Gas 1 units and
explained in the proposal its rationale
for such standards, including the fact
that a significant portion of the
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emissions data were below the detection
level. 75 FR at 32024–25. Therefore, the
petitioner had the opportunity to
comment on this issue, and did in fact
submit comments regarding the EPA’s
legal authority to establish work
practice standards for Gas 1 units.
Therefore, the EPA is denying
reconsideration on this issue.
Issue: Work practices for small units
are not justified by 112(h) since small
units were not given their own
subcategory.
The petitioner (Sierra Club) requested
that the EPA require small units, those
having a heat input capacity of less than
10 MMBtu/hr, to meet numeric
emissions limits rather than work
practice standards. The EPA is denying
the request for reconsideration on this
issue because the petitioner has not
demonstrated that it lacked the
opportunity to comment on this issue.
The EPA proposed work practice
standards for these units and explained
in the proposal its rationale for such
standards. 75 FR at 32024–25. The EPA
did in fact receive comments regarding
the proposed standards, to which it
responded in the final rule. 76 FR at
15640. Moreover, the EPA notes that
nothing in section 112(h) limits the
EPA’s discretion to establish work
practice standards to the establishment
of such standards for an entire category
or subcategory. Therefore, the EPA is
denying the request for reconsideration.
Issue: PM is not an adequate
surrogate for non-mercury metallic
HAP.
The petitioner (Sierra Club) requested
that the EPA remove the PM standard as
a surrogate for non-mercury metallic
HAP and instead adopt a numeric limit
for non-mercury metallic HAP because
PM is not an appropriate surrogate. The
EPA is denying the request for
reconsideration on this issue. While the
EPA disagrees with the petitioner’s
argument regarding the suitability of PM
as a surrogate for non-mercury metallic
HAP, the petitioner has not
demonstrated that it lacked the
opportunity to comment on this issue.
The EPA proposed PM standards as a
surrogate for non-mercury metallic HAP
and explained in the proposal the
agency’s basis for concluding that PM
was an appropriate surrogate. 75 FR at
32018. Therefore, the EPA is denying
the request for reconsideration.
Issue: Establish direct limits on
organics or select a surrogate besides
CO.
The petitioner (Sierra Club) requested
that the EPA remove the CO standard as
a surrogate for organic HAP and instead
adopt a numeric limit for these HAP,
because CO is not an appropriate
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surrogate. The EPA is denying the
request for reconsideration on this issue.
While the EPA disagrees with the
petitioner’s argument regarding the
suitability of CO as a surrogate for
organic HAP, the petitioner has not
demonstrated that it lacked the
opportunity to comment on this issue.
The EPA proposed CO standards as a
surrogate for organic HAP and
explained in the proposal the agency’s
basis for concluding that CO was an
appropriate surrogate. 75 FR at 32018.
The EPA received comments on this
issue, including comments stating that
CO is not an appropriate surrogate for
organic HAP. Therefore, the EPA is
denying the request for reconsideration.
Issue: Adopt an alternative THC
emission standard.
The petitioner (CIBO) requested that
the EPA adopt a THC emissions
standard as an alternative to the CO
standard. The EPA is denying the
request for reconsideration on this issue.
While the EPA disagrees with the
petitioner’s argument regarding whether
a THC alternative standard is
appropriate as a surrogate for nondioxin organic HAP, the petitioner has
not demonstrated that it lacked the
opportunity to comment on this issue.
The EPA raised in the proposal the
possibility of THC as a surrogate for
non-dioxin organic HAP, and explained
why the use of CO as a surrogate was
preferable. 75 FR at 32018. In addition,
the EPA did not receive any comments
or data during the public comment
period on the proposed rule that would
have enabled the agency to establish a
THC alternative standard, including
THC emissions data, nor did the
petitioner provide any such data.
Therefore, the petition does not provide
substantial support for its argument that
the final rule should be changed. For
these reasons, the EPA is denying the
petition for reconsideration on this
issue.
Issue: Regulation of Total dioxin/
furans exceeds statutory authority as
only 2 compounds are in 112(b)(1).
The petitioners (AISI, ACCCI, AF&PA)
alleged that the EPA lacks statutory
authority to regulate total dioxin/furans
under CAA section 112, and that the
EPA’s response in the final rule
explaining why it is issuing a total
dioxin/furan standard was not a logical
outgrowth of the proposed rule. The
EPA is denying the request for
reconsideration on this issue. First, the
EPA disagrees that the final rule is not
a logical outgrowth of the proposal. The
EPA proposed emissions standards for
total dioxin/furans and adopted a final
emissions standard for the same
pollutant. Therefore, the commenter had
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the opportunity to provide its views
during the public comment period
regarding the EPA’s proposed emissions
standard, including its views regarding
the EPA’s authority to regulate the
pollutant at issue. The fact that the EPA
responded to those comments does not
mean that the petitioner lacked the
opportunity to comment—in fact, the
petitioner did provide such comments.
76 FR at 15640. For this reason, the EPA
is denying the petition for
reconsideration.
Issue: HCl is an inadequate surrogate
for all acid gases.
The petitioner (Sierra Club) requested
that the EPA remove the HCl standard
as a surrogate for acid gases and instead
adopt a numeric limit for these HAP,
because HCl is not an appropriate
surrogate. The EPA is denying the
request for reconsideration on this issue.
While the EPA disagrees with the
petitioner’s argument regarding the
suitability of HCl as a surrogate for acid
gases, the petitioner has not
demonstrated that it lacked the
opportunity to comment on this issue.
The EPA proposed HCl standards as a
surrogate for acid gases and explained
in the proposal the agency’s basis for
concluding that HCl was an appropriate
surrogate. 75 FR at 32018. While the
EPA had emission data for HCl from
hundreds of affected units upon which
to establish standards, the EPA did not
have sufficient data on the other acid
gases to do so (hydrogen fluoride,
hydrogen cyanide and chlorine). The
petitioner did not refer to any such data
and, therefore, the issue is not of central
relevance to the outcome of the final
rule. Therefore, the EPA is denying the
request for reconsideration.
Issue: Establish work practice for
other organic HAP instead of using CO
as a surrogate.
The petitioners (AMP, JELD–WEN)
requested that the EPA adopt a work
practice standard for organic HAP rather
than a numeric emissions limit based on
CO as a surrogate for organic HAP. The
EPA is denying the request for
reconsideration on this issue. While the
EPA disagrees that a work practice
standard is appropriate for such HAP for
the subcategories for which the EPA
adopted a numeric CO limit in the final
rule, the petitioners have not
demonstrated that they lacked the
opportunity to comment on this issue.
The EPA proposed numeric CO limits
rather than a work practice, and the
petitioners had the opportunity to
provide their views during the public
comment period on the proposed rule
regarding why it believed a work
practice standard should instead be
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finalized. Therefore, the EPA is denying
the petition for reconsideration.
Issue: Allow health based compliance
alternatives for HCl, other acid gases
and manganese.
The petitioners (AMP, AF&PA,
AHFA, AISI, ACCCI, RPU, CIBO)
requested that the EPA adopt a HBES for
HCl and other acid gases as well as for
manganese, pursuant to section
112(d)(4). The petitioners also requested
that the EPA grant reconsideration on
this issue to better address the
comments and data submitted during
the public comment period for the
proposed rule. The EPA is denying the
request for reconsideration of this issue.
The EPA did not propose a HBES for
any pollutants, but did solicit public
comment on such standards, explaining
its concerns regarding health-based
standards, including the lack of
available data on which to base such
standards. 75 FR at 32030. The EPA
received comments addressing those
concerns and responded to them in the
final rule. 76 FR at 15642. Therefore, the
petitioners have not demonstrated that
it lacked the opportunity to comment on
this issue. Further, the EPA received no
data during the public comment period
for the proposed rule on which it could
base a HBES for HCl, other acid gases
or manganese. Therefore, the petitions
do not provide substantial support to
demonstrate that the final rule should
be changed. For these reasons, the EPA
is denying the petition for
reconsideration.
Issue: Provide additional compliance
alternatives according to Executive
Order 13563 (additional subcategories
and HBES).
The petitioner (AHFA) requested that
the EPA provide additional compliance
alternatives in the final rule pursuant to
Executive Order 13563 (Improving
Regulation and Regulatory Review),
including HBES. The EPA is denying
the request for reconsideration on this
issue because it is not of central
relevance. First, nothing in Executive
Order 13563 affects the EPA’s discretion
to establish HBES under the CAA.
Additionally, the petition does not
provide any information to address our
concerns regarding HBES or data to
establish such standards.
Issue: Remove energy assessment
requirements.
The petitioners (AHFA, AISI, ACCCI,
API, NPRA, AIF, CIBO, AF&PA, U.S.
Sugar) requested that the EPA remove
from the final rule the requirement that
existing sources conduct an energy
assessment. The EPA is denying the
request for reconsideration on this issue.
The EPA proposed an energy
assessment requirement as a beyond-
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the-floor standard, and petitioners
commented on that proposal. The EPA
addressed those comments in the final
rule, and petitioners have not
demonstrated that they lacked the
opportunity to comment on whether the
EPA should require an energy
assessment, including the EPA’s legal
authority to do so. 76 FR at 15631.
Therefore, the EPA is denying the
petition for reconsideration. The EPA
continues to believe that an energy
assessment is not only authorized by the
CAA but required as a cost-effective
beyond-the-floor standard in accordance
with section 112(d)(2).
Issue: Require energy assessment to be
conducted every 5 years.
The petitioner (Washington Dept. of
Ecology) requested that the EPA require
more frequent energy assessments. The
EPA proposed a one-time assessment
(75 FR at p. 32036) and the petitioner
has not demonstrated it lacked the
opportunity to comment on the
frequency of the assessment
requirement. Therefore, the EPA is
denying the petition.
Issue: Modify cost analysis to include
potential fuel savings from
implementing assessment findings.
The petitioners (AIE, USCHPA)
requested that the EPA modify its cost
impacts analysis to include potential
fuel savings from implementing energy
assessment findings. The EPA is
denying the petition. The impacts
analysis, including specific mention of
how cost savings for energy assessments
were handled quantitatively, was
explained in the proposal (see 75 FR
32026), and the petitioner therefore had
the opportunity to comment on this
issue. For this reason, the EPA is
denying the petition for reconsideration
on this issue.
Issue: Reconsider definition of ‘‘cost
effective.’’
The petitioners (AIE, USCHPA)
requested that the EPA reconsider the
definition of ‘‘cost-effective’’ in the final
rule. The EPA is denying the request for
reconsideration on this issue. The EPA
proposed to define cost-effective energy
conservation measures as any measure
with return of investment period of two
years or less. 75 FR at 32036. The
petitioners have not demonstrated it
lacked the opportunity to comment on
the proposed definition. Therefore, the
EPA is denying the petition for
reconsideration.
Issue: Establish work practice for
other organic HAP instead of using CO
surrogate.
The petitioners (AMP, JELD–WEN)
requested that the EPA establish work
practice standards for controlling
organic HAP instead of using CO as a
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surrogate for organic HAP and
establishing CO emission limits. The
EPA is denying the request for
reconsideration on this issue. Use of CO
as a surrogate for organic HAP was
subject to notice and comment. (75 FR
32018, 75 FR 32041). Responses to
comment on this topic were provided in
RTC document, Volume 2, EPA–HQ–
OAR–2002–0058–3289, see section
‘‘Choice of Regulated Pollutants: THC
vs. CO vs. Other Organic HAP’’.
Issue: Provide alternative format for
units of measure for CO emission limits
to allow sources to use their existing
monitoring equipment.
The petitioners (UARG, CIBO)
requested that the EPA provide an
alternative format (ppm at X percent
CO2) for units of measure for CO
emissions in addition to ppm at 3
percent oxygen. The EPA is denying the
petition because the petitioners do not
demonstrate that it was impracticable to
comment on this issue. The format for
units of measure for the limits was
provided in the proposed rule, and
petitioners could have commented on
whether the proposed units were
appropriate.
Issue: New source emission limits are
unachievable and the EPA should
collect additional fuel variability data
from top performing units to adjust the
limits.
The petitioner (AF&PA) requested
that the EPA adjust the emissions limits
for new sources by collecting additional
data from the best performing units that
they believed would result in increased
variability. The petitioners have not
demonstrated that they lacked the
opportunity to comment. We proposed
standards based on the data we had,
including data collected during the ICR
process in which petitioners
participated, and that data were
available for public review. Therefore,
petitioners could have commented on
this issue. Second, the CAA requires
that we base the standards on the
sources for which we have emissions
information. Petitioners are always free
to provide more information to us and
the EPA specifically requested new data
at each stage of the rulemaking to
support the development of emission
limits for each subcategory. (75 FR
32041, 76 FR 28663, 76 FR 80612). The
EPA has incorporated revised data
corrections or new data submittals in its
analysis for the final rule. The EPA is
denying the request for reconsideration.
Issue: Adjust the methodology for
computing MACT floors to address
statistical errors and variability
concerns.
The petitioners (AISI, ACCCI, AF&PA)
requested that the EPA adjust the
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methodology for computing MACT
floors to address statistical errors and
variability concerns, including: (1)
Dataset reflects the ‘‘best of the best’’
units; (2) misapplication of statistical
formulae to address distribution,
confidence limits, and variability; and
(3) failure to address variability in
emissions from one unit over time. The
methods used to compute the MACT
floors were subject to notice and
comment. Where new data or data
corrections have been submitted that
might alter data distributions,
identifying best performers or
application of fuel variability factors,
these changes have been made in the
final rule, but the general methodology
remains the same. See Solite Corp. v.
EPA, 952 F.2d 473, 485 (D.C. Cir. 1991)
(public had sufficient notice of final rule
threshold calculations where
methodology did not change
significantly from proposed rule). The
EPA explained the MACT floor
methodology in the proposed rule, and
addressed comments received on the
proposed methodology in the final rule
(75 FR 32019–26, 32027–29, 76 15621–
30, 76 FR 80614). Therefore, the EPA is
denying the request for reconsideration.
Issue: Modify the basis for ranking the
top performing units.
The petitioner (WEPCO) requested
that the EPA modify the basis for
ranking the top performing units,
especially for new units, according to
the average performance of the unit. The
EPA is denying the petition. The
methods used to rank units to establish
the MACT floors were subject to notice
and comment. The EPA explained its
methodology in the proposed rule and
addressed comments received on the
ranking of data for computing the
MACT floor in the final rule (75 FR
32019–26, 32027–29, 76 FR 15627).
Issue: Do not use a pollutant-bypollutant approach to establish MACT
floors.
The petitioners (AISI, ACCCI, AF&PA)
requested that the EPA not use a
pollutant-by-pollutant approach to
establish MACT floors. The petitioners
stated that this method is not a
reasonable interpretation of Section
112(d)(3) of the CAA and that MACT
floors should reflect levels achieved in
practice, not aspirational controls. The
EPA is denying the petition for
reconsideration on this issue because it
does not demonstrate that it was
impracticable to comment on the issue.
The EPA proposed MACT floors based
on the pollutant-by-pollutant
methodology, and therefore petitioners
could, and in fact did, provide
comments opposing this approach. See
75 FR 32021, 32029. The EPA addressed
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comments received on this approach in
the final rule (76 FR 15621–23).
Therefore, the EPA is denying the
petition.
Issue: Revise approach to establish
MACT floors where there is non-detect
data.
The petitioner (Sierra Club) requested
that the EPA not use the approach it
used in the final rule based on the
representative detection level (RDL) to
establish MACT floors because it does
not reflect actual emissions of any
source within the subcategory. Further,
the petitioner questioned the basis of
the selected detection level, and
whether or not other variability
adjustments (e.g., UPL analysis)
sufficiently account for measurement
imprecision. The EPA is denying the
petition. The three times representative
detection level approach was subject to
notice and comment. The EPA
explained its rationale for this approach
in the proposed rule (75 FR 32021) and
responded to comments received in the
final rule (76 FR 15623, 76 FR 80611).
Issue: The approach used to set
MACT floor limits for dioxin/furan
emissions is flawed and the EPA should
establish an isomer-specific approach.
The petitioner (WEPCO) requested
that the EPA establish an isomerspecific approach for dioxin/furan
emissions because the three times
detection level approach for dioxin/
furan emissions is flawed. The EPA is
denying the petition. This approach was
subject to notice and comment.
Rationale and responses to comments
on this approach were provided at (75
FR 32021, 32041, 76 FR 15623). Further,
the methods for establishing a
representative detection level for
dioxin/furan have been revised to
account for the sensitivity of individual
isomers, see rationale provided at (76
FR 80606).
Issue: Incorporate a fuel variability
factor for PM based on the ash content
of the fuel used by best performing
units.
The petitioners (WEPCO, CIBO)
requested that the EPA incorporate a
fuel variability factor for PM based on
the ash content of the fuel used by best
performing units. The MACT floor
methodology was explained in the June
4, 2010 proposal which included fuel
variability factors that did not reflect the
ash content of the fuel. Therefore, the
petitioner could have commented
recommending that the EPA do so, and,
in fact, comments were provided on this
issue. The EPA is denying the petition
for reconsideration on this issue because
it does not demonstrate that it was
impracticable to comment on the issue.
Responses to comment on this topic
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7151
were provided in RTC document,
Volume 1, EPA–HQ–OAR–2002–0058–
3289, see section ‘‘MACT Floor
Methodology: Fuel Analysis
Variability’’.
Issue: Allow energy assessors to
determine the time needed to conduct
assessment.
The petitioner (Washington Dept. of
Ecology) requested that the EPA allow
the energy assessor to determine the
time needed to conduct the energy
assessment. The EPA is denying the
petition. The duration of energy
assessments was subject to notice and
comment and the duration remains up
to the affected source. Specific concerns
with maximum duration requirements
included in the March 21, 2011 final
rule were clarified in the December 23,
2011 proposed notice of
reconsideration. (76 FR 80615)
Issue: The unit designed to burn gas
1 subcategory should allow for limited
use of liquid fuels.
The petitioners (ACC, CEG, API,
NPRA) requested that the EPA allow
units in the Gas 1 subcategory for
limited use of liquid fuels; for example,
units with a federally enforceable
permit on back up fuels or units burning
10 percent or less of its heat input from
liquid fuels should qualify as gas 1
units. The EPA is denying the petition
because it does not demonstrate that it
was impracticable to comment on the
issue. The EPA proposed definitions of
the various subcategories, and
petitioners had the opportunity to
comment on those definitions,
including the proposed definition of the
Gas 1 subcategory which did allow for
the limited use of liquid fuels. The EPA
addressed comments received on this
issue in the final rule (76 FR 15620).
Issue: The unit designed to burn gas
1 subcategory should automatically
include other gaseous fuels such as
petrochemical process gas and landfill
gas.
The petitioners (ACC, AIF, WM)
requested that the EPA redefine the unit
designed to burn gas 1 subcategory to
automatically include other gaseous
fuels such as petrochemical process gas
and LFG, especially when the LFG is
routed to a treatment system prior to use
or sale. The EPA proposed definitions of
units designed to burn gas 1 and units
designed to burn gas 2 (other), and
therefore the petitioner had the
opportunity to comment on these
definitions and to recommend that other
gases be included in the definition of
the Gas 1 subcategory (75 FR 32017,
32065). The EPA addressed comments
received on this issue in the final rule
(76 FR 15638). Therefore, the EPA is
denying the petition.
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Issue: Reconsider the emission
standards established for the unit
designed to burn gas 2 subcategory.
Petitioners (AIF, CIBO, WM, CEG)
requested that the EPA reconsider the
emission standards for the unit designed
to burn gas 2 subcategory in light of
what they feel was a limited dataset and
lack of data from a diverse set of fuel
types. The EPA is denying the petition.
The MACT floor methodology was open
to notice and comment in the June 4,
2010 proposal. The EPA proposed
emissions standards for this subcategory
and the petitioners had an opportunity
to comment on the proposed standards
and the data on which the standards
were based. The EPA further notes that
the CAA requires that the MACT
standards be based on the best
performing sources for which the
Administrator has emissions
information.
Issue: Adjust the ‘‘metal process
furnaces’’ subcategory definition to
include any gas-fired process furnace.
The petitioners (AISI, ACCCI)
requested that the EPA adjust the ‘‘metal
process furnaces’’ subcategory
definition to include any gas-fired
process furnace. The EPA is denying the
petition. The definition of the
subcategory for metal process furnaces
was subject to notice and comment. (75
FR 32064, 76 FR 15620).
Issue: The designed to burn rationale
for subcategorization is arbitrary.
The petitioner (Sierra Club) alleged
that the designed to burn rationale for
subcategorization is arbitrary, especially
considering the large number of co-fired
units in the inventory. The EPA
proposed subcategories based on boiler
design, and the petitioner has not
demonstrated that it was impracticable
to comment on the issue. In fact, the
petitioner did submit comments on the
proposed rule opposing the EPA’s
proposed subcategorization approach.
Therefore, the EPA is denying the
petition.
Issue: The EPA should consider
exempting units from NSR.
The petitioners (MSU, PSU, Purdue,
Citizens Thermal Energy) requested that
the EPA consider exempting units from
NSR who switch fuels, install pollution
controls, or construct energy efficiency
projects to meet the requirements of this
rule because complying with the rule
requirements will trigger NSR. The EPA
is denying the petition. The
applicability of NSR is outside the scope
of this rulemaking. Moreover, it was not
impracticable to comment on this issue
during the 2011 rulemaking, in fact,
comments were submitted on this issue,
to which the EPA responded. See RTC
document, Volume 2, EPA–HQ–OAR–
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2002–0058–3289, DCN EPA–HQ–OAR–
2002–0058–2729.1, excerpt 17.
Issue: Remove the 10 percent penalty
for sources opting to use the emission
averaging compliance alternative.
The petitioners (AMP, MSU, PSU,
Purdue, RPU, U.S. Sugar, Citizens
Thermal Energy) requested that the EPA
remove the 10 percent penalty for
sources opting to use the emission
averaging compliance alternative. The
EPA is denying the petition. The EPA
proposed an emissions averaging
approach that included the 10 percent
adjustment factor. (75 FR 32035)
Therefore, the petition does not
demonstrate that it was impracticable to
comment on this issue. Responses to
comment on this topic were provided in
RTC document, Volume 2, EPA–HQ–
OAR–2002–0058–3289, see section
‘‘Emissions Averaging.’’
Issue: Allow emissions averaging
across subcategories.
The petitioners (MSU, PSU, Purdue,
RPU, Citizens Thermal Energy)
requested that the EPA allow emissions
averaging across subcategories. The EPA
is denying the petition. The EPA
proposed an emissions averaging
approach that did not allow averaging
across subcategories, and petitioners
therefore had the opportunity to
comment recommending that the EPA
allow such averaging. Responses to
comment on this topic were provided in
RTC document, Volume 2, EPA–HQ–
OAR–2002–0058–3289, DCN EPA–HQ–
OAR–2002–0058–3213.1, excerpt 175.
Issue: Allow a source’s actual heat
input instead of the maximum design
heat input to be used in the emissions
averaging provisions.
The petitioner (CIBO) requested that
the EPA allow a source’s actual heat
input instead of the maximum design
heat input to be used in the emissions
averaging provisions of the final rule.
The EPA proposed an emissions
averaging approach that was based on
the maximum rated heat input capacity,
and petitioners therefore had the
opportunity to comment recommending
that the EPA base the averaging on
actual heat input. Therefore, the EPA is
denying the petition.
Issue: Reduce stack testing frequency
to once every five years to reduce
burden on facilities.
The petitioners (ACC, CIBO, JELD–
WEN) requested that the EPA reduce
stack testing frequency to once every 5
years and rely on the extensive set of
continuous parameter monitoring in
order to reduce burden on facilities. The
EPA is denying the petition. The EPA
proposed to require stack testing every
year. The petition does not demonstrate
that it was impracticable to comment on
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this issue, and the petitioners could
have submitted comments requesting
less frequent stack testing.
Issue: Incorporate detailed fuel
sampling procedures using
incorporation by reference mechanisms
instead of detailing sampling
procedures in the regulatory language.
The petitioner (CIBO) requested that
the EPA incorporate detailed fuel
sampling procedures using
incorporation by reference mechanisms
and citing credible literature (e.g.,
American Society for Testing and
Materials) instead of detailing sampling
procedures in the regulatory language
since sampling procedures are subject to
change over time. The EPA is denying
the petition because the petitioner has
not demonstrated that it was
impracticable to comment on this issue.
The EPA proposed fuel sampling
procedures in the regulatory text in the
June 4, 2010 proposal, and the
petitioner therefore had the opportunity
to comment recommending its preferred
approach.
Issue: Remove the advanced submittal
requirement for site-specific fuel
monitoring plans before each analysis.
The petitioner (UARG) requested that
the EPA remove the advanced submittal
requirement for site-specific fuel
monitoring plans before each analysis,
especially if monthly frequency is
maintained. If the fuel monitoring plan
requirement remains, the petitioner
requests that the EPA remove the
requirement to report things that might
change, such as unanticipated fuel use
(based on unanticipated fuel changes).
The EPA is denying the petition and
disagrees with the commenter. First, the
EPA proposed a fuel monitoring plan,
and petitioners had the opportunity to
comment on the plan requirement. The
final rule requires submittal of a fuel
monitoring plan 60 days before
demonstrating initial compliance. The
rule does not require re-submittal of this
plan before each monthly analysis, see
40 CFR section 63.7521(b)(1).
Issue: Allow EPA Method 5B to
demonstrate compliance with PM
emission limits.
The petitioner (UARG) requested that
the EPA allow EPA Method 5B to
demonstrate compliance with PM
emission limits. The EPA is denying the
petition because it does not demonstrate
that it was impracticable to comment on
this issue. The EPA proposed methods
to demonstrate compliance in the June
4, 2010 proposal and did not propose to
allow Method 5B for PM compliance
demonstrations. Therefore, the
petitioner had the opportunity to submit
comments recommending that the EPA
allow the use of this method. For this
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reason, the EPA is denying the petition
on this issue.
Issue: Remove or make references to
Methods 2, 2F, 2G and 4 optional.
The petitioner (UARG) requested that
the EPA remove or make references to
EPA Methods 2, 2F, 2G and 4 optional.
The EPA is denying the petition because
it does not demonstrate that it was
impracticable to comment on this issue.
The EPA proposed methods to
demonstrate compliance in the June 4,
2010 proposal and did not propose to
make EPA Methods 2, 2F, 2G and 4
optional. Therefore, the petitioner had
the opportunity to submit comments
recommending that the EPA make the
use of these methods optional. For this
reason, the EPA is denying the petition
on this issue.
Issue: Allow sources to petition for
alternative PM monitoring requirements
based on source-specific limitations.
The petitioner (CEG) requested that
the EPA allow sources to petition for
alternative PM monitoring requirements
based on source-specific limitations
(e.g., common stacks with more than
one subcategory). The EPA is denying
this petition because it is not of central
relevance to this rulemaking. The
General Provisions at 40 CFR 63.8 allow
sources to petition the EPA for
alternative monitoring plans. Therefore,
no such provision is needed in this final
rule.
Issue: Allow sources with overlapping
CEMS regulations to comply with
existing QA/QC plans or 40 CFR part 75
Appendices A and B.
The petitioners (CIBO, CMI) requested
that the EPA allow sources with
overlapping CEMS regulations to
comply with existing QA/QC plans or
40 CFR part 75 Appendices A and B.
The EPA is denying this petition
because it is not of central relevance to
this rulemaking.
Issue: No justification or discussion
was provided on why the EPA selected
12 hours as the averaging time period
and also why the EPA selected block
averages instead of rolling averages.
The petitioner (Sierra Club) alleges
that the EPA provided no justification or
discussion explaining why the EPA
selected 12 hours as the averaging time
period and why the EPA selected block
averages instead of rolling averages for
parameter monitor. The petitioner
requested that the EPA clarify that the
averaging times for continuous
parameter monitoring should be the
same as the averaging times during the
most recent performance test. Averaging
times were open to notice and comment
in the June 4, 2010 proposal. In the June
2010 proposal, we required that
parameters be set based on 4-hour block
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averages during the compliance test,
and that continuous compliance be
demonstrated by monitoring 12-hour
block average values for most
parameters. We selected this averaging
period to reflect operating conditions
during the performance test to ensure
the control system is continuously
operating at the same or better level as
during a performance test demonstrating
compliance with the emission limits.
Therefore, the EPA is denying the
petition.
Issue: The EPA position regarding
treatment of ‘‘out-of-control’’ and
‘‘maintenance’’ periods as deviations is
not supported or explained.
The petitioner (UARG) alleges that the
EPA position regarding treatment of
‘‘out-of-control’’ and ‘‘maintenance’’
periods as deviations is not supported
or explained. The petitioner requested
that the EPA revise the definition of
‘‘deviation’’ to be consistent with how
deviation is treated with respect to CO
CEMS and CPMS. The EPA is denying
the petition. The definition of
deviations was open to notice and
comment in the June 4, 2010 proposal.
Issue: Require checks of pressure
monitoring taps only if reading is
abnormal.
The petitioner (CMI) requested that
the EPA require checks of pressure
monitoring taps only if reading is
abnormal. The requirement to check
pressure tap pluggage daily was open to
notice and comment in the June 2010
proposal. In addition, the EPA is
denying this petition because it is not of
central relevance to this rulemaking.
Issue: The EPA has not sufficiently
correlated emission limits to operating
parameters and should not set
enforceable limits on maximum and
minimum control device operating
parameters.
The petitioners (UARG, AMP, CIBO)
alleges that the EPA has not sufficiently
correlated emission limits to operating
parameters and requested the EPA not
to set enforceable limits on maximum
and minimum control device operating
parameters. One petitioner (CIBO)
requested that the rule should allow
sources to set their own ESP secondary
voltage requirement based on load and
coal quality since power consumption
by an ESP is influenced by factors other
than operating load, including ESP
design, amount of PM collected, and
resistivity of the PM. Other petitioners
(UARG and AMP) also indicate that the
limits set on control devices inhibit the
flexibility to operate control devices
with a margin of safety. The EPA is
denying the petition. Operating limits
were open to notice and comment in the
June 4, 2010 proposal.
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Issue: The EPA should delay
incorporating PS 17 in this rule until the
revisions for PS 17 are completed.
The petitioner (UARG) requested that
the EPA delay incorporating PS 17 in
this rule, which outlines how to select
and install CPMS, until the revisions for
PS 17 are completed.
The EPA is denying this petition. The
final rule did not incorporate PS 17, or
any other PS, in the provision regarding
selection and installation of CPMS and
ongoing quality assurance of data from
CPMS. Comments related to revising PS
17 are outside the scope of this
rulemaking. (RTC document, Chapter
11, EPA–HQ–OAR–2002–0058–3289,
DCN EPA–HQ–OAR–2002–0058–
2960.1, excerpt 150).
Issue: The EPA should not set an
enforceable operating limit on opacity.
The petitioner (UARG) alleged that
there is insufficient correlation between
opacity and PM emissions and
requested that the EPA not set an
enforceable operating limit on opacity.
The EPA is denying the petition. The
EPA proposed opacity limits in the June
4, 2010 proposal and the petitioner
therefore had the opportunity to
comment on the proposed limits,
including comments requesting that no
limit be established.
Issue: Update outdated BLDS
Guidance.
The petitioner (UARG) requested that
the EPA update the outdated BLDS
Guidance that is currently incorporated
by reference. The EPA is denying this
petition. The current guidance
document is the most recent guidance
available and comments related to
revising the guidance document are
outside the scope of this rulemaking.
(RTC document, Chapter 11, EPA–HQ–
OAR–2002–0058–3289, DCN EPA–HQ–
OAR–2002–0058–2997.1, excerpt 10).
Issue: The EPA should reconsider
emission limits for HCl on coal-fired
boilers using a hot-side ESP for
particulate control.
The petitioners (MSU, PSU, Purdue,
Citizens Thermal Energy) requested that
the EPA reconsider emission limits for
HCl on coal-fired boilers using a hotside ESP for particulate control. The
petitioners are unaware of any HCl
control devices that are compatible with
a hot-side ESP. The EPA is denying the
petition. The basis for subcategorization
was subject to notice and comment. The
EPA did not propose a separate
subcategory for such units, and the
petitioner could have commented
recommending that the agency do so.
(75 FR 32012, 76 FR 15617–18, 76 FR
80607) Further, the EPA disagrees with
the petitioner that the subcategories
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could be based on the level of controls
installed on the unit.
Issue: The EPA should change
electronic reporting requirements to
avoid WebFIRE and ERT shortcomings.
The petitioner (UARG) requested that
the EPA change the electronic reporting
requirements to avoid WebFIRE and
ERT shortcomings. The petitioner
requested that to meet the EPA’s
obligations under the Paperwork
Reduction Act the EPA specify each
individual data item requested in the
ERT. The petitioner also requests that
the EPA explain how the ERT electronic
signature mechanisms will meet the
requirements of the Cross-Media
Electronic Reporting Rule.
The EPA is denying the petition
because it does not demonstrate that it
was impracticable to comment on this
issue. The EPA proposed to require the
use of the ERT and WebFIRE, and the
petitioner therefore had the opportunity
to comment on any concerns with the
proposed approach.
Issue: Eliminate gas curtailment
notification requirements or adjust the
frequency of these notifications to be
consistent with the reporting
requirements in the Title V program.
The petitioner (AIF) requested that
the EPA eliminate the gas curtailment
notification requirements or adjust the
frequency of these notifications to be
consistent with the semi-annual
reporting requirements in the Title V
program. The EPA is denying the
petition. Reporting requirements were
open to notice and comment in the June
4, 2010 proposal.
Issue: Allow facilities to become area
or synthetic minor sources instead of
installing controls.
The petitioner (GPSP) requested that
the EPA allow facilities to become area
or synthetic minor sources instead of
installing controls. The EPA is denying
the petition. Whether or not sources
elect to become area or synthetic minor
sources is not of central relevance to
this rulemaking, as nothing in this rule
affects whether or how a source can
become a synthetic minor source (RTC
document, EPA–HQ–OAR–2002–0058–
3289, Volume 1, DCN EPA–HQ–OAR–
2002–0058–3176.2, excerpt 4).
VI. Impacts of This Final Rule
A. What are the incremental air
impacts?
Table 4 of this preamble illustrates,
for each basic fuel subcategory, the total
emissions reductions achieved by the
final amended rule (i.e., the difference
in emissions between a boiler or process
heater controlled to the amended floor
level of control and boilers or process
heaters at the current baseline) for new
and existing sources. Nationwide
emissions of selected HAP (i.e., HCl,
HF, mercury, metals, and VOC) will be
reduced by 44,300 tpy. This is an
incremental increase of 4,000 tpy in
HAP reductions compared to the
estimates in the March 2011 final rule.
This increase is due mainly to changes
in the inventory (336 units were added
since the March 2011 inventory).
Excluding the changes in the inventory,
the amendments to the regulatory
provisions themselves resulted in a
decrease of 1,100 tpy of estimated
reductions, part of this incremental
reduction in HAP is contributed to edits
to the baseline emission data received
since the March 2011 final rule, as well
as changes to the subcategories and
emission limits as a result of this
amended rule. The amendments to the
final rule are expected to result in an
additional 4,600 tpy of reductions in
HCl emissions. The amendments are
also expected to have a modest effect on
mercury, estimated to range from a
slight decrease of 0.12 tpy up to a slight
increase of 0.96 tpy in emission
reductions as a result of the changes to
the regulatory requirements. Reductions
in emissions of filterable PM will
decrease by 18,500 tpy due to the final
amended rule. Reductions in emissions
of non-mercury metals (i.e., antimony,
arsenic, beryllium, cadmium,
chromium, cobalt, lead, manganese,
nickel, and selenium) will decrease by
260 tpy. In addition, the amendments
are estimated to result in an additional
50,100 tpy of reductions in SO2
emissions. A discussion of the
methodology used to estimate
emissions, emissions reductions, and
incremental emission reductions is
presented in ‘‘Revised (August 2012)
Methodology for Estimating Cost and
Emission Impacts for Industrial,
Commercial, and Institutional Boilers
and Process Heaters NESHAP—Major
Source’’ in the docket.
TABLE 4—SUMMARY OF TOTAL EMISSIONS REDUCTIONS FOR THE FINAL AMENDED RULE
[tons/yr]
Source
Subcategory
Existing Units .......................................
New Units ............................................
Non
mercury
metals a
HCl
PM
Limited Use ..........................................
Solid units ............................................
Liquid units ...........................................
Non-Continental Liquid units ...............
Gas 1 (NG/RG) units ...........................
Gas 1 Metallurgical Furnaces ..............
Gas 2 (other) units ...............................
1
36,737
2,143
35
20
0.4
4
2
21,367
9,434
3
117
3
8
0.42
147
2,315
1
0.3
0.02
0.06
Solid units ............................................
Liquid units ...........................................
Gas 1 units ..........................................
Gas 1 Metallurgical Furnaces ..............
Gas 2 (other) units ...............................
0
0
0
0
0
351
0
0
0
0
5
0
0
0
0
a Includes
2.1E–04 .......
0.4 to 1.5 .....
0.9 to 1 ........
0.01 to 0.02
0.01 .............
0.001 ...........
3.8E–03 to
4.6E–03.
0.02 .............
0 ..................
0 ..................
0 ..................
0 ..................
VOC
0.48
1,619
620
23
88
27
40
0
0
0
0
0
antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium.
reductions are presented as a range due to adjustments on reported fractions and limits of detection. See memorandum entitled
‘‘Revised (March 2012) Methodology for Estimating Cost and Emissions Impacts for Industrial, Commercial, Institutional Boilers and Process
Heaters National Emission Standards for Hazardous Air Pollutants—Major Source’’ for a description of the two methods for estimating mercury
reductions.
b Mercury
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B. What are the incremental water and
solid waste impacts?
The EPA estimated the additional
water usage that would result from
installing wet scrubbers to meet the
amended emission limits for HCl would
be 556 million gallons per year for
existing sources compared to the current
baseline. In addition to the increased
water usage, an additional 160 million
gallons per year of wastewater would be
produced for existing sources. Only half
of these incremental changes are due to
changes in the regulatory provisions.
The other half is due to changes in the
number of identified existing units and
projected new units. The annual costs of
treating the additional wastewater are
$1.2 million. These additional costs are
accounted for in the incremental control
cost estimates.
The EPA estimated the additional
solid waste that would result due to the
amendments to be 138,000 tpy, with
nearly all due to changes in the
regulatory provisions. Solid waste is
generated from flyash and dust captured
in PM and mercury controls as well as
from spent carbon that is injected into
exhaust streams or used to filter gas
streams. The costs of handling the
additional solid waste generated are
$5.8 million. These costs are also
accounted for in the incremental control
costs estimates.
A discussion of the methodology used
to estimate incremental impacts is
presented in ‘‘Revised (August 2012)
Methodology for Estimating Cost and
Emission Impacts for Industrial,
Commercial, and Institutional Boilers
and Process Heaters NESHAP—Major
Source’’ in the docket.
C. What are the incremental energy
impacts?
The EPA estimated that the March
2011 final rule would result in an
increase of about 1.4 billion kWh/yr in
national energy usage from the
electricity required to operate control
devices, such as wet scrubbers,
electrostatic precipitators and fabric
filters which are expected to be installed
to meet the final rule. The amendments
are expected to decrease energy usage
by a net 143 million kWh/yr compared
to the March 2011 rule. These
reductions are driven by the regulatory
provisions of these amendments.
Additionally, the EPA expects these
amendments will result in a decrease of
4.4 million MMBtu/yr in fuel savings,
compared with the estimates in the
March 2011 final rule.
D. What are the incremental cost
impacts?
For these final amendments, we
estimated the incremental difference
between the national costs impacts for
the final amended rule and the March
2011 final rule. First, we determined the
control measures, work practices, and
monitoring and testing requirements
that would be required by boilers and
process heaters located at major source
facilities to comply with the final
amended rule. To estimate the national
cost impacts of the final amended rule
for existing sources, we used the
identical methodology used to estimate
the cost impacts for the March 2011
final rule with one exception. In this
revised analysis, it was assumed that
several liquid fuel units that reported
natural gas firing capability would
switch to natural gas as a compliance
option instead of installing add-on
controls to demonstrate compliance
with the emission limits. Thus, the only
costs to these units would be the tuneup work practice costs. A discussion of
the methodology used to estimate cost
impacts is presented in ‘‘Revised
(August 2012) Methodology for
Estimating Cost and Emission Impacts
for Industrial, Commercial, and
Institutional Boilers and Process Heaters
NESHAP—Major Source’’ in the docket.
The resulting total national cost
impact of the final amended rule is $4.7
billion in capital expenditures and $1.5
billion per year in total annual costs,
considering fuel savings. The total
capital expenditures are slightly lower
than estimated for the March 2011 final
7155
rule, but the total annual costs are
slightly higher than estimated for the
March 2011 final rule. See 76 FR 15651.
The total capital and annual costs
include costs for control devices, work
practices, testing and monitoring.
In order to determine the incremental
cost impacts of the amended
requirements and emission limits, we
first estimated the cost impacts of the
additional existing boilers and process
heaters added to the Boiler MACT
inventory database since promulgation
of the March 2011 final rule and the
revised number of new boilers and
process heaters that could be potentially
constructed. Since the March 2011 final
rule, we became aware of 72 major
source facilities that were not
previously in the Boiler MACT
inventory database. Adding the boilers
and process heaters located at these
newly identified major source facilities
resulted in 73 additional coal-fired
units, 32 additional biomass-fired units,
82 additional oil-fired units, and 149
additional gas-fired units. Our revised
number of new boilers and process
heaters included 82 additional biomass
units, 1,728 additional gas 1 units and
13 fewer liquid units.
The resulting cost impact for these
additional existing and new boilers and
process heaters is $1.0 billion in capital
expenditures and $0.31 billion per year
in total annual costs, considering fuel
savings.
Therefore, discounting the added
costs for the additional boilers and
process heaters included in the costs
analysis, the estimated incremental cost
impacts for these amended requirements
on existing and new boilers and process
heaters are $1.0 billion in capital
expenditures and $0.13 billion per year
in total annual costs less than the costs
estimated in the March 2011 rule.
Table 5 of this preamble shows the
total capital and annual cost impacts of
the final amended rule for each
subcategory. Costs include testing and
monitoring costs, but not recordkeeping
and reporting costs.
TABLE 5—SUMMARY OF TOTAL CAPITAL AND ANNUAL COSTS FOR NEW AND EXISTING SOURCES FOR THE FINAL AMENDED
RULE
Subcategory
Existing Units ...................................
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Estimated/
projected
number of
affected units
Coal units .........................................
Biomass units ..................................
Heavy Liquid units ...........................
Light Liquid units ..............................
Non-Continental Liquid units ...........
Gas 1 (NG/RG) units .......................
621 ..............
502 ..............
319 ..............
615 ..............
21 ................
11,929 .........
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Capital costs
(106 $)
2,554
405
761
712
62
77
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Testing and
monitoring
annualized
costs
(106 $/yr)
46
29
5.4
4.2
0.8
0.9
Annualized cost
(106 $/yr)
(considering
fuel savings)
904
109
221
166
17
(295)
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Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
TABLE 5—SUMMARY OF TOTAL CAPITAL AND ANNUAL COSTS FOR NEW AND EXISTING SOURCES FOR THE FINAL AMENDED
RULE—Continued
Estimated/
projected
number of
affected units
Source
Subcategory
Energy Assessment .........................
Gas 2 (other) units ...........................
ALL ...................................................
New Units ........................................
a Total
Coal units .........................................
Biomass units ..................................
Liquid units .......................................
Gas 1 (NG/RG) units .......................
Gas 2 (other) units ...........................
Testing and
monitoring
annualized
costs
(106 $/yr)
Capital costs
(106 $)
129 ..............
1,700 (Facilities).
0 ..................
82 ................
0 ..................
1,762 ...........
0 ..................
138
N/A
2.3
N/A
0
381
0
11
0
Annualized cost
(106 $/yr)
(considering
fuel savings)
0
5.6
0
0
0
0
a 99
0
a 5.1
0
annualized costs for new units do not account for fuel savings since no fuel savings are estimated in the first year for new units.
Potential control device cost savings
and increased recordkeeping and
reporting costs associated with the
emissions averaging provisions in the
final rule are not accounted for in either
the capital or annualized cost estimates.
A discussion of the methodology used
to estimate cost impacts is presented in
‘‘Revised (August 2012) Methodology
for Estimating Cost and Emission
Impacts for Industrial, Commercial, and
Institutional Boilers and Process Heaters
NESHAP—Major Source’’ in the docket.
E. What are the economic impacts?
The EPA analyzed the economic
impacts of this final amended rule using
the methodology that was discussed in
the March 2011 final rule RIA and in the
preamble to the March 2011 final rule.
See FR 76 15651. The market impact
results are very similar to the results
presented in the March 2011 final rule
and the RIA. The agency’s economic
model suggests the average national
price increases for industrial sectors are
less than 0.01 percent, while average
annual domestic production may fall by
less than 0.01 percent.
Because of higher domestic prices,
imports slightly rise. The results for
sales tests for small businesses were
somewhat reduced than those
calculated for the March 2011 final rule.
For the sales tests using small
companies identified in the Combustion
Survey, the mean cost to receipts
dropped from 4 percent in the RIA to 3
percent for this final amended rule and
the median was 0.2 percent for the RIA
and also 0.2 percent for this final
amended rule. The number of parent
companies with sales tests exceeding 3
percent dropped from 8 in the RIA to 5
for this final amended rule. There was
no change in the results for small public
entities. Median cost is still about $1.1
million and representative small major
public entities would have cost-torevenue ratios above 10 percent. The
change in employment estimates
between the RIA and the final amended
rule is minimal. In the RIA for the
March 2011 final rule, we estimated
employment changes ranging between
¥3,100 to +6,500 employees, with a
central estimate of +1,700. For this final
amended rule we estimate employment
changes ranging between ¥2,600 to
+5,400 employees, with a central
estimate of +1,400. These estimated
annual employment changes compared
to the baseline employment, and are for
the time period for which the
annualized cost applies (2015 to 2029).
F. What are the benefits of this final
rule?
We calculated health benefits using
the methodology described in the RIA
prepared for the March 21, 2011 final
rule. We incorporated the revised
emission reductions estimated for this
reconsideration final rule into the
analysis. We were unable to estimate the
benefits from reducing exposure to HAP
and ozone, ecosystem impairment and
visibility impairment, including
reducing 180,000 tons of carbon
monoxide, 39,000 tons of HCl, 500 tons
of HF, 2,500 tons of other metals and
3,100 to 5,300 pounds of mercury.
Please refer to the full description of the
unquantified benefits as well as
technical details of the analysis and its
limitations and uncertainties in the final
Boiler RIA (March 2011). These
monetized benefits are approximately
23 percent higher than the March 2011
final rule benefits due to the increase in
SO2 emission reductions associated
with the additional units affected by the
rule and the revised HCl limit. We
estimate the total monetized benefits of
this final regulatory action to be $27
billion to $67 billion at a 3 percent
discount rate and $25 to $61 billion at
a 7 percent discount rate. All estimates
are for the implementation year (2015)
in 2008$. A summary of the monetized
benefits estimates at discount rates of 3
percent and 7 percent is provided in
Table 6 of this preamble. A summary of
the avoided health incidences is
provided in Table 7 of this preamble.
TABLE 6—SUMMARY OF THE MONETIZED BENEFITS ESTIMATES FOR THE FINAL BOILER MACT
[millions of 2008$] a b
Pollutant
Emissions
reductions
(tons)
Total monetized benefits
(at 3% discount rate)
Total monetized benefits
(at 7% discount rate)
PM2.5-related benefits
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28
Direct PM2.5 ............................
SO2 ........................................
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$26,000 to $64,000 ............................................
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$24,000 to $61,000
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7157
TABLE 6—SUMMARY OF THE MONETIZED BENEFITS ESTIMATES FOR THE FINAL BOILER MACT—Continued
[millions of 2008$] a b
Pollutant
Emissions
reductions
(tons)
Total ................................
Total monetized benefits
(at 3% discount rate)
Total monetized benefits
(at 7% discount rate)
$27,000 to $67,000 ............................................
$25,000 to $61,000.
a All
estimates are for the implementation year (2015), and are rounded to two significant figures so numbers may not sum across rows. All
fine particles are assumed to have equivalent health effects because the scientific evidence is not yet sufficient to allow differentiation of effect
estimates by particle type. Benefits from reducing hazardous air pollutants (HAP) are not included. These estimates do not include energy
disbenefits valued at $24 million (using a 3 percent discount rate). These benefits reflect existing boilers and new boilers anticipated to come online by 2015.
b There are some slight differences in the emission reductions used in the RIA and those used in the air impacts section of this preamble due
to some late changes in the data that were received after the RIA was completed. Refer to the memoranda ‘‘Revised (August 2012) Methodology
for Estimating Cost and Emission Impacts for Industrial, Commercial, and Institutional Boilers and Process Heaters NESHAP—Major Source’’ for
a discussion of the differences.
TABLE 7—SUMMARY OF THE AVOIDED additional electricity would yield slight
HEALTH INCIDENCES FOR THE FINAL increases in emissions, including NOX,
CO, PM and SO2 and an increase in CO2
BOILER MACT a
Avoided health
incidences
Premature Mortality ..............
Morbidity ...............................
Chronic Bronchitis ................
Acute Myocardial Infarction ..
Hospital Admissions, Respiratory ..............................
Hospital Admissions, Cardiovascular .............................
Emergency Room Visits,
Respiratory ........................
Acute Bronchitis ....................
Work Loss Days ...................
Asthma Exacerbation ...........
Minor Restricted Activity
Days ..................................
Lower Respiratory Symptoms ..................................
Upper Respiratory Symptoms ..................................
3,000–7,900
........................
2,000
5,000
750
1,600
3,000
4,600
390,000
51,000
2,300,000
55,000
41,000
a All estimates are for the implementation
year (2015), and are rounded to two significant figures. All fine particles are assumed to
have equivalent health effects because the
scientific evidence is not yet sufficient to allow
differentiation of effect estimates by particle
type. Benefits from reducing HAP are not included. These benefits reflect existing boilers
and new boilers anticipated to come online by
2015.
G. What are the incremental secondary
air impacts?
For units adding controls to meet the
amended emission limits, we anticipate
very minor secondary air impacts. The
combustion of fuel needed to generate
emissions. Since NOX and SO2 are
covered by capped emissions trading
programs and methodological
limitations prevent us from quantifying
the change in CO and PM, we do not
estimate an increase in secondary air
impacts for this final rule from
additional electricity demand. We do
estimate greenhouse gas impacts, which
result from increased electricity
consumption, to be 859,200 tpy from
existing units and 79,700 tpy from new
units. This is 19,200 tpy less than the
estimated greenhouse gas impacts
associated with the March 2011 final
rule.
VII. Statutory and Executive Order
Reviews
A. Executive Order 12866: Regulatory
Planning and Review and Executive
Order 13563: Improving Regulation and
Regulatory Review
Under section 3(f)(1) of Executive
Order 12866 (58 FR 51735, October 4,
1993), this action is an ‘‘economically
significant regulatory action’’ because it
is likely to have an annual effect on the
economy of $100 million or more or
adversely affect in a material way the
economy, a sector of the economy,
productivity, competition, jobs, the
environment, public health or safety, or
state, local, or tribal governments or
communities. Accordingly, the EPA
submitted this action to the OMB for
review under Executive Orders 12866
and 13563 (76 FR 3821, January 21,
2011) and any changes made in
response to the OMB recommendations
have been documented in the docket for
this action.
The EPA did prepare a new RIA for
this action. The EPA prepared an
assessment of the changes in the costs
and benefits of this final rule compared
to the costs and benefits associated with
the March 21, 2011, final rule. Overall,
the costs and impacts are estimated to
be similar to the costs and impacts
associated with the previous final rule,
although the distribution is somewhat
different and the number of affected
units in the inventory has increased by
about 302 units. When comparing the
costs using only those sources that were
part of the final rule inventory, the costs
have decreased. The EPA re-ran the
multimarket model to assess changes in
economic impacts, and this analysis
confirmed that the overall economic
impacts are similar to the previous final
rule. The benefits are projected to
increase by about 20 percent because of
the increase in the estimated SO2
reductions. A summary of the costs and
benefits of the previous final rule is
provided in the preamble to the
previous final rule (see 76 FR 15658)
and the detailed analysis for the
previous final rule is provided in the
RIA for the previous final rule. In
addition, memoranda are provided in
the docket to document the changes in
costs, economic impacts, and benefits
associated with this final rule, shown in
Table 8.
TABLE 8—SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS AND NET BENEFITS FOR THE FINAL BOILER MACT
RECONSIDERATION IN 2015
[Millions of 2008$] 1
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Total Monetized Benefits 2 .................................
Total Social Costs 3 ............................................
Net Benefits ........................................................
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$1,400 to $1,600 ..............................................
$26,000 to $65,000 ..........................................
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$24,000 to $61,000.
$1,400 to $1,600.
$23,200 to $59,000.
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Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
TABLE 8—SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS AND NET BENEFITS FOR THE FINAL BOILER MACT
RECONSIDERATION IN 2015—Continued
[Millions of 2008$] 1
3 percent discount rate
Non-monetized Benefits .....................................
7 percent discount rate
Health effects from exposure to HAP (39,000 tons of HCl, 500 tons of HF, 3,100 to 5,300
pounds of mercury, and 2,500 tons of other metals).
Health effects from exposure to other criteria pollutants (180,000 tons of CO and 572,000 tons
of SO2).
Ecosystem effects.
Visibility impairment.
1 All
estimates are for the implementation year (2015), and are rounded to two significant figures.
total monetized co-benefits reflect the human health benefits associated with reducing exposure to PM2.5 through reductions of PM2.5
precursors such as directly emitted particles, SO2, and NOX and reducing exposure to ozone through reductions of VOC. It is important to note
that the monetized benefits include many but not all health effects associated with PM2.5 exposure. Monetized benefits are shown as a range
from Pope et al. (2002) to Laden et al. (2006). These models assume that all fine particles, regardless of their chemical composition, are equally
potent in causing premature mortality because the scientific evidence is not yet sufficient to support the development of differential effects estimates by particle type. These estimates include the energy disbenefits valued at $24 million (using the 3 percent discount rate), which do not
change the rounded totals. CO2-related disbenefits were calculated using the ‘‘social cost of carbon’’, which is discussed further in the RIA.
3 The methodology used to estimate social costs for one year in the multimarket model using surplus changes results in the same social costs
for both discount rates.
tkelley on DSK3SPTVN1PROD with
2 The
B. Paperwork Reduction Act
The OMB has approved the
information collection requirements
contained in the March 21, 2011 final
rule under the provisions of the
Paperwork Reduction Act, 44 U.S.C.
3501 et seq. and has assigned OMB
control number 2060–0551. The EPA
has updated the supporting statement to
reflect the final inventory and burden
estimates associated with this action
since some of the monitoring,
recordkeeping and reporting
requirements have changed since the
March 21, 2011 final rule. These revised
estimates have been sent to OMB for
review and approval.
The information requirements are
based on notification, recordkeeping,
and reporting requirements in the
NESHAP General Provisions (40 CFR
part 63, subpart A), which are
mandatory for all operators subject to
national emission standards. These
recordkeeping and reporting
requirements are specifically authorized
by section 114 of the CAA (42 U.S.C.
7414). All information submitted to the
EPA pursuant to the recordkeeping and
reporting requirements for which a
claim of confidentiality is made is
safeguarded according to agency
policies set forth in 40 CFR part 2,
subpart B.
This final rule will require
maintenance inspections of the control
devices but will not require any
notifications or reports beyond those
required by the General Provisions aside
from a notification of intent to
commence burning solid waste
materials and notification of alternative
fuel use for those units that are in the
Gas 1 subcategory but burn liquid fuels
for periodic testing, or during periods of
gas curtailment or gas supply
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emergencies. The recordkeeping
requirements require only the specific
information needed to determine
compliance.
The revised annual monitoring,
reporting and recordkeeping burden for
this collection (averaged over the first 3
years after the effective date of the
standards) is estimated to be $95.3
million which is about the same as
estimated for the March 2011 final rule.
This includes 323,130 labor hours per
year at a total labor cost of $30.6 million
per year, and total non-labor capital
costs of $64.7 million per year. This
estimate includes initial and annual
performance test, conducting and
documenting an energy assessment,
conducting fuel specifications for Gas 1
units, repeat testing under worst-case
conditions for solid fuel units,
conducting and documenting a tune-up,
semiannual excess emission reports,
maintenance inspections, developing a
monitoring plan, notifications and
recordkeeping. Monitoring, testing,
tune-up and energy assessment costs
and cost were also included in the cost
estimates presented in the control costs
impacts estimates in section VI.D of this
preamble. The total burden for the
federal government (averaged over the
first 3 years after the effective date of the
standard) is estimated to be 100,608
hours per year at a total labor cost of
$5.3 million per year. Burden is defined
at 5 CFR 1320.3(b).
An agency may not conduct or
sponsor, and a person is not required to
respond to, a collection of information
unless it displays a currently valid OMB
control number. The OMB control
numbers for the EPA’s regulations in 40
CFR are listed in 40 CFR part 9. In
addition, the EPA is amending the table
in 40 CFR part 9 of currently approved
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OMB control numbers for various
regulations to list the regulatory
citations for the information
requirements contained in this final
rule.
C. Regulatory Flexibility Act
The RFA generally requires an agency
to prepare a regulatory flexibility
analysis of any rule subject to notice
and comment rulemaking requirements
under the Administrative Procedure Act
or any other statute unless the agency
certifies that the rule will not have a
significant economic impact on a
substantial number of small entities.1
The RFA also allows an agency to
‘‘consider a series of closely related
rules as one rule for the purposes of
sections’’ 603 (initial regulatory
flexibility analysis) and 604 (final
regulatory flexibility analysis) in order
to avoid ‘‘duplicative action.’’ 5 U.S.C.
§ 605(c). This final rule is closely related
to the final major source rule, which the
EPA signed on February 21, 2011. The
EPA prepared a final regulatory
flexibility analyses in connection with
the major source rule. Therefore,
1 Small entities include small businesses, small
organizations, and small governmental
jurisdictions. For purposes of assessing the impacts
of today’s rule on small entities, small entity is
defined as: (1) A small business according to Small
Business Administration (SBA) size standards by
the North American Industry Classification System
category of the owning entity. The range of small
business size standards for the affected industries
ranges from 500 to 1,000 employees, except for
petroleum refining and electric utilities. In these
latter two industries, the size standard is 1,500
employees and a mass throughput of 75,000 barrels/
day or less, and 4 million kilowatt-hours of
production or less, respectively; (2) a small
governmental jurisdiction that is a government of a
city, county, town, school district or special district
with a population of less than 50,000; and (3) a
small organization that is any not-for-profit
enterprise which is independently owned and
operated and is not dominant in its field.
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pursuant to § 605(c), the EPA is not
required to complete a final regulatory
flexibility analysis for this rule.
The EPA has been concerned with
potential small entity impacts since it
began developing the major source rule.
The EPA conducted outreach to small
entities and, pursuant to § 609 of RFA,
convened a Small Business Advocacy
Review Panel to obtain advice and
recommendations from small entity
representatives.
Pursuant to the RFA, the EPA used
the Panel’s report and prepared both an
initial regulatory flexibility analysis and
a final regulatory flexibility analysis in
connection with the closely related
major source rule. Convening an
additional Panel and preparing an
additional final regulatory flexibility
analysis would be procedurally
duplicative and is unnecessary given
that the issues here are within the scope
of those considered by the Panel. In
addition, this final action would
decrease capital and annualized costs
on small entities by about 3 percent and
10 percent, respectively, relative to the
closely related final rule.
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D. Unfunded Mandates Reform Act
Title II of the UMRA of 1995, 2 U.S.C.
1531–1538, requires federal agencies,
unless otherwise prohibited by law, to
assess the effects of their regulatory
actions on state, local and tribal
governments and the private sector.
Federal agencies must also develop a
plan to provide notice to small
governments that might be significantly
or uniquely affected by any regulatory
requirements. The plan must enable
officials of affected small governments
to have meaningful and timely input in
the development of the EPA regulatory
proposals with significant Federal
intergovernmental mandates and must
inform, educate, and advise small
governments on compliance with the
regulatory requirements.
Both this rule and the March 21, 2011
final rule contain a federal mandate that
may result in expenditures of $100
million or more for state, local and tribal
governments, in the aggregate, or the
private sector in any one year.
Accordingly, the EPA prepared under
section 202 of the UMRA a written
statement for the final rule. This final
rule also contains a federal mandate that
may result in expenditures of $100
million or more for state, local, and
tribal governments, in the aggregate, or
the private sector in any one year. The
discussion below has been updated to
reflect the changes.
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1. Statutory Authority
As discussed in the March 21, 2011,
final rule, the statutory authority for this
final rulemaking is section 112 of the
CAA. Title III of the CAA Amendments
was enacted to reduce nationwide air
toxic emissions. Section 112(b) of the
CAA lists the 188 chemicals,
compounds, or groups of chemicals
deemed by Congress to be HAP. These
toxic air pollutants are to be regulated
by NESHAP.
Section 112(d) of the CAA directs us
to develop NESHAP which require
existing and new major sources to
control emissions of HAP using MACT
based standards. This NESHAP applies
to all boilers and process heaters located
at major sources of HAP emissions.
2. Social Costs and Benefits
The regulatory impact analysis
prepared for the March 21, 2011 final
rule, which we have revised for this
final rule, including the agency’s
assessment of costs and benefits, is
detailed in the ‘‘Regulatory Impact
Analysis for the Final Industrial Boilers
and Process Heaters MACT (2011)’’ and
in the ‘‘Regulatory Impact Results for
the Reconsideration Final Rule for
National Emission Standards for
Hazardous Air Pollutants for Industrial,
Commercial, and Institutional Boilers
and Process Heaters at Major Sources’’
in the docket. Based on estimated
compliance costs associated with this
final rule and the predicted change in
prices and production in the affected
industries, the estimated social costs of
this rule are $1.4 to 1.6 billion (2008
dollars).
It is estimated that 3 years after
implementation of this final rule, HAP
would be reduced by 45,000 tpy,
including reductions in HCl, hydrogen
fluoride, metallic HAP including
mercury, and several other organic HAP
from boilers and process heaters.
Studies have determined a relationship
between exposure to these HAP and the
onset of cancer, however, the agency is
unable to provide a monetized estimate
of the HAP benefits at this time. In
addition, there are significant annual
reductions in fine particulate matter
(PM2.5) and in SO2 that would occur,
including 25 thousand tons of PM2.5 and
558 thousand tons of SO2. These
reductions occur within 3 years after the
implementation of the final regulation
and are expected to continue throughout
the life of the affected sources. The
major health effect associated with
reducing PM2.5 and PM2.5 precursors
(such as SO2) are a reduction in
premature mortality. Other health
effects associated with PM2.5 emission
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reductions include avoiding cases of
chronic bronchitis, heart attacks, asthma
attacks and work-lost days (i.e., days
when employees are unable to work).
While we are unable to monetize the
benefits associated with the HAP
emissions reductions, we are able to
monetize the benefits associated with
the PM2.5 and SO2 emissions reductions.
For SO2 and PM2.5, we estimated the
benefits associated with health effects of
PM but were unable to quantify all
categories of benefits (particularly those
associated with ecosystem and visibility
effects). Our estimates of the monetized
benefits in 2015 associated with the
implementation of the final regulatory
action range from $27 billion (2008
dollars) to $67 billion (2008 dollars)
when using a 3 percent discount rate (or
from $25 billion (2008 dollars) to $61
billion (2008 dollars) when using a 7
percent discount rate). This estimate, at
a 3 percent discount rate, is about $25
billion (2008 dollars) to $65 billion
(2008 dollars) higher than the estimated
social costs shown earlier in this
section. The general approach used to
value benefits is discussed in more
detail earlier in this preamble. For more
detailed information on the benefits
estimated for the rulemaking, refer to
the RIA and the memos updating the
impacts and benefits in the docket.
3. Future and Disproportionate Costs
The UMRA requires that we estimate,
where accurate estimation is reasonably
feasible, future compliance costs
imposed by this final rule and any
disproportionate budgetary effects. Our
estimates of the future compliance costs
of the rule are discussed previously in
this preamble.
We do not believe that there will be
any disproportionate budgetary effects
of this final rule on any particular areas
of the country, state or local
governments, types of communities
(e.g., urban, rural) or particular industry
segments. See the results of the
‘‘Regulatory Impact Analysis for the
Final Industrial Boilers and Process
Heaters MACT (2011).’’
4. Effects on the National Economy
The UMRA requires that we estimate
the effect of this final rule on the
national economy. To the extent
feasible, we must estimate the effect on
productivity, economic growth, full
employment, creation of productive jobs
and international competitiveness of the
U.S. goods and services, if we determine
that accurate estimates are reasonably
feasible and that such effect is relevant
and material.
The nationwide economic impact of
this final rule is presented in the
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tkelley on DSK3SPTVN1PROD with
‘‘Regulatory Impact Analysis for the
Final Industrial Boilers and Process
Heaters MACT (2011)’’ and a
memoranda that are included in the
docket, entitled ‘‘Regulatory Impact
Results for the Reconsideration Final
Rule for National Emission Standards
for Hazardous Air Pollutants for
Industrial, Commercial, and
Institutional Boilers and Process Heaters
at Major Sources which update the RIA
analyses. This analysis provides
estimates of the effect of this rule on
some of the categories mentioned above.
The results of the economic impact
analysis are summarized previously in
this preamble. The results show that
there will be a small impact on prices
and output, and little impact on
communities that may be affected by
this final rule. In addition, there should
be little impact on energy markets (in
this case, coal, natural gas, petroleum
products and electricity). Hence, the
potential impacts on the categories
mentioned above should be small.
5. Consultation With Government
Officials
The UMRA requires that we describe
the extent of the agency’s prior
consultation with affected state, local
and tribal officials, summarize the
officials’ comments or concerns, and
summarize our response to those
comments or concerns. In addition,
section 203 of the UMRA requires that
we develop a plan for informing and
advising small governments that may be
significantly or uniquely impacted by a
final rule. We consulted with state and
local air pollution control officials
during the development of the final
rule. We have also held meetings on this
final rule with many of the stakeholders
from numerous individual companies,
institutions, environmental groups,
consultants and vendors, labor unions
and other interested parties. We have
added materials to the docket to
document these meetings.
Consistent with section 205, the EPA
has identified and considered a
reasonable number of regulatory
alternatives. Additional information on
the costs and environmental impacts of
these regulatory alternatives is
presented in the docket.
The regulatory alternative upon
which the emission limits in this final
rule are based represents the MACT
floors for all subcategories and, as a
result, it is the least costly and least
burdensome alternative.
This rule is not subject to the
requirements of section 203 of UMRA
because it contains no regulatory
requirements that might significantly or
uniquely affect small governments.
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While some small governments may
have some sources affected by this final
rule, the impacts are not expected to be
significant. Therefore, this final rule is
not subject to the requirements of
section 203 of the UMRA.
E. Executive Order 13132: Federalism
This action does not have federalism
implications. It will not have substantial
direct effects on the states, on the
relationship between the national
government and the states, or on the
distribution of power and
responsibilities among the various
levels of government, as specified in
Executive Order 13132. This final rule
will not impose direct compliance costs
on state or local governments, and will
not preempt state law. Thus, Executive
Order 13132 does not apply to this
action.
F. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
This action does not have tribal
implications, as specified in Executive
Order 13175 (65 FR 67249, November 9,
2000). It will not have substantial direct
effects on tribal governments, on the
relationship between the federal
government and Indian tribes, or on the
distribution of power and
responsibilities between the federal
government and Indian tribes, as
specified in Executive Order 13175.
Thus, Executive Order 13175 does not
apply to this action.
G. Executive Order 13045: Protection of
Children From Environmental Health
Risks and Safety Risks
The EPA interprets Executive Order
13045 (62 FR 19885, April 23, 1997) as
applying to those regulatory actions that
concern health or safety risks, such that
the analysis required under section 5–
501 of the Order has the potential to
influence the regulation. This action is
not subject to EO 13045 because it is
based solely on technology
performance.
H. Executive Order 13211: Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use
This action is not a ‘‘significant
energy action’’ as defined in Executive
Order 13211 (66 FR 28355, May 22,
2001), because it is not likely to have a
significant adverse effect on the supply,
distribution, or use of energy. For the
March 21, 2011, final rule, we estimated
a 0.05 percent price increase for the
energy sector and a ¥0.02 percent
percentage change in production. We
estimated a 0.09 percent increase in
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energy imports. For more information
on the estimated energy effects, please
refer to the ‘‘Regulatory Impact Analysis
for the Final Industrial Boilers and
Process Heaters MACT (2011).’’ The
analysis is available in the public
docket. While we did not recreate the
RIA for this final action, the energy
impacts for existing sources decreased
slightly, and the energy impacts for new
source increased due to the increased
number of new sources that is now
projected. Overall, the projected energy
use increased slightly but would not
change the analysis that was conducted
for the previous final rule. Therefore, we
conclude that this final rule when
implemented is not likely to have a
significant adverse effect on the supply,
distribution, or use of energy.
I. National Technology Transfer and
Advancement Act
Section 12(d) of the NTTAA, Public
Law 104–113, 12(d) (15 U.S.C. 272 note)
directs the EPA to use VCS in its
regulatory activities unless to do so
would be inconsistent with applicable
law or otherwise impractical. VCS are
technical standards (e.g., materials
specifications, test methods, sampling
procedures, and business practices) that
are developed or adopted by VCS
bodies. NTTAA directs the EPA to
provide Congress, through the OMB,
explanations when the agency decides
not to use available and applicable VCS.
This action does not involve any new
technical standards from those
contained in the March 21, 2011 final
rule. Therefore, the EPA did not
consider the use of any VCS. See 76 FR
15660–15662 for the NTTAA discussion
in the March 21, 2011 final rule.
J. Executive Order 12898: Federal
Actions To Address Environmental
Justice in Minority Populations and
Low-Income Populations
Executive Order 12898 (59 FR 7629,
February 16, 1994) establishes federal
executive policy on environmental
justice. Its main provision directs
federal agencies, to the greatest extent
practicable and permitted by law, to
make environmental justice part of their
mission by identifying and addressing,
as appropriate, disproportionately high
and adverse human health or
environmental effects of their programs,
policies, and activities on minority
populations and low-income
populations in the United States.
For the March 2011 final rule, the
EPA determined that the rule would not
have disproportionately high and
adverse human health or environmental
effects on minority or low-income
populations because it increases the
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level of environmental protection for all
affected populations without having any
disproportionately high and adverse
human health or environmental effects
on any population, including any
minority or low-income population.
Compared to the previous final rule,
while the amendments are somewhat
less stringent for some subcategories of
units and more stringent for some
others, the overall increased health
benefits demonstrate that the
conclusions from the environmental
justice analysis conducted for the
previous final rule are still valid.
Therefore, the EPA has determined this
final rule will not have
disproportionately high and adverse
human or environmental effects on
minority or low-income populations.
K. Congressional Review Act
The Congressional Review Act, 5
U.S.C. 801 et seq., as added by the Small
Business Regulatory Enforcement
Fairness Act of 1996, generally provides
that before a rule may take effect, the
agency promulgating the rule must
submit a rule report, which includes a
copy of the rule, to each House of the
Congress and to the Comptroller General
of the United States. EPA will submit a
report containing this final rule and
other required information to the U.S.
Senate, the U.S. House of
Representatives, and the Comptroller
General of the United States prior to
publication of the rule in the Federal
Register. A major rule cannot take effect
until 60 days after it is published in the
Federal Register. This action is a ‘‘major
rule’’ as defined by 5 U.S.C. 804(2).
With the exception of the May 18, 2011
(76 FR 28661), delay of the effective
date revising subpart DDDDD at 76 FR
15451 (March 21, 2011) being lifted
January 31, 2013, this rule will be
effective April 1, 2013.
List of Subjects in 40 CFR Part 63
Environmental protection,
Administrative practice and procedure,
Air pollution control, Hazardous
substances, Incorporation by reference,
Intergovernmental relations, Reporting
and Recordkeeping requirements.
tkelley on DSK3SPTVN1PROD with
Dated: December 20, 2012
Lisa P. Jackson,
Administrator.
For the reasons cited in the preamble,
title 40, chapter I, part 63 of the Code
of Federal Regulations is amended as
follows:
PART 63—[AMENDED]
1. The authority for part 63 continues
to read as follows:
■
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Authority: 42 U.S.C. 7401, et seq.
2. Effective January 31, 2013, the May
18, 2011 (76 FR 28661), delay of the
effective date revising subpart DDDDD
at 76 FR 15451 (March 21, 2011) is
lifted.
■
Subpart A—[Amended]
3. Section 63.14 is amended by:
a. Revising paragraphs (b)(19), (b)(23),
(b)(35), (b)(40), (b)(69), and (b)(70).
■ b. Removing and reserving paragraph
(b)(53).
■ c. Adding paragraphs (b)(46), (b)(55),
and (b)(76) through (83).
■ d. Adding paragraphs (p)(12) through
(20).
■ e. Adding paragraph (r).
The revisions and additions read as
follows:
■
■
§ 63.14
Incorporations by reference.
*
*
*
*
*
(b) * * *
(19) ASTM D95–05 (Reapproved
2010), Standard Test Method for Water
in Petroleum Products and Bituminous
Materials by Distillation, approved May
1, 2010, IBR approved for § 63.10005(i)
and table 6 to subpart DDDDD.
*
*
*
*
*
(23) ASTM D4006–11, Standard Test
Method for Water in Crude Oil by
Distillation, including Annex A1 and
Appendix X1, approved June 1, 2011,
IBR approved for § 63.10005(i) and table
6 to subpart DDDDD.
*
*
*
*
*
(35) ASTM D6784–02 (Reapproved
2008) Standard Test Method for
Elemental, Oxidized, Particle-Bound
and Total Mercury in Flue Gas
Generated from Coal-Fired Stationary
Sources (Ontario Hydro Method),
approved April 1, 2008, IBR approved
for table 1 to subpart DDDDD of this
part, table 2 to subpart DDDDD of this
part, table 5 to subpart DDDDD, table 11
to subpart DDDDD of this part, table 12
to subpart DDDDD of this part, table 13
to subpart DDDDD of this part, and table
4 to subpart JJJJJJ of this part.
*
*
*
*
*
(40) ASTM D396–10 Standard
Specification for Fuel Oils, approved
October 1, 2010, IBR approved for
§ 63.7575 and § 63.11237.
*
*
*
*
*
(46) ASTM D4606–03 (2007),
Standard Test Method for Determination
of Arsenic and Selenium in Coal by the
Hydride Generation/Atomic Absorption
Method, approved October 1, 2007, IBR
approved for table 6 to subpart DDDDD.
*
*
*
*
*
(55) ASTM D6357–11, Test Methods
for Determination of Trace Elements in
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Coal, Coke, and Combustion Residues
from Coal Utilization Processes by
Inductively Coupled Plasma Atomic
Emission Spectrometry, approved April
1, 2011, IBR approved for table 6 to
subpart DDDDD.
*
*
*
*
*
(69) ASTM D4057–06 (Reapproved
2011), Standard Practice for Manual
Sampling of Petroleum and Petroleum
Products, including Annex A1,
approved June 1, 2011, IBR approved for
§ 63.10005(i) and table 6 to subpart
DDDDD.
(70) ASTM D4177–95 (Reapproved
2010), Standard Practice for Automatic
Sampling of Petroleum and Petroleum
Products, including Annexes A1
through A6 and Appendices X1 and X2,
approved May 1, 2010, IBR approved for
§ 63.10005(i) and table 6 to subpart
DDDDD.
*
*
*
*
*
(76) ASTM D6751–11b, Standard
Specification for Biodiesel Fuel Blend
Stock (B100) for Middle Distillate Fuels,
approved July 15, 2011, IBR approved
for § 63.7575 and § 63.11237.
(77) ASTM D975–11b, Standard
Specification for Diesel Fuel Oils,
approved December 1, 2011, IBR
approved for § 63.7575.
(78) ASTM D5864–11 Standard Test
Method for Determining Aerobic
Aquatic Biodegradation of Lubricants or
Their Components, approved March 1,
2011, IBR approved for table 6 to
subpart DDDDD.
(79) ASTM D240–09 Standard Test
Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb
Calorimeter, approved July 1, 2009, IBR
approved for table 6 to subpart DDDDD.
(80) ASTM D4208–02 (2007) Standard
Test Method for Total Chlorine in Coal
by the Oxygen Bomb Combustion/Ion
Selective Electrode Method, approved
May 1, 2007, IBR approved for table 6
to subpart DDDDD.
(81) ASTM D5192–09 Standard
Practice for Collection of Coal Samples
from Core, approved June 1, 2009, IBR
approved for table 6 to subpart DDDDD.
(82) ASTM D7430–11ae1, Standard
Practice for Mechanical Sampling of
Coal, approved October 1, 2011, IBR
approved for table 6 to subpart DDDDD.
(83) ASTM D6883–04, Standard
Practice for Manual Sampling of
Stationary Coal from Railroad Cars,
Barges, Trucks, or Stockpiles, approved
June 1, 2004, IBR approved for table 6
to subpart DDDDD.
*
*
*
*
*
(p) * * *
(12) Method 5050 (SW–846–5050),
Bomb Preparation Method for Solid
Waste, Revision 0, September 1994, in
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EPA Publication No. SW–846, Test
Methods for Evaluating Solid Waste,
Physical/Chemical Methods, Third
Edition IBR approved for table 6 to
subpart DDDDD.
(13) Method 9056 (SW–846–9056),
Determination of Inorganic Anions by
Ion Chromatography, Revision 1,
February 2007, in EPA Publication No.
SW–846, Test Methods for Evaluating
Solid Waste, Physical/Chemical
Methods, Third Edition, IBR approved
for table 6 to subpart DDDDD.
(14) Method 9076 (SW–846–9076),
Test Method for Total Chlorine in New
and Used Petroleum Products by
Oxidative Combustion and
Microcoulometry, Revision 0,
September 1994, in EPA Publication No.
SW–846, Test Methods for Evaluating
Solid Waste, Physical/Chemical
Methods, Third Edition, IBR approved
for table 6 to subpart DDDDD.
(15) Method 1631 Revision E,
Mercury in Water by Oxidation, Purge
and Trap, and Cold Vapor Atomic
Absorption Fluorescence Spectrometry,
Revision E, EPA–821–R–02–019, August
2002, IBR approved for table 6 to
subpart DDDDD.
(16) Method 200.8, Determination of
Trace Elements in Waters and Wastes by
Inductively Coupled Plasma—Mass
Spectrometry, Revision 5.4, 1994, IBR
approved for table 6 to subpart DDDDD.
(17) Method 6020A (SW–846–6020A),
Inductively Coupled Plasma-Mass
Spectrometry, Revision 1, February
2007, in EPA Publication No. SW–846,
Test Methods for Evaluating Solid
Waste, Physical/Chemical Methods,
Third Edition, IBR approved for table 6
to subpart DDDDD.
(18) Method 6010C (SW–846–6010C),
Inductively Coupled Plasma-Atomic
Emission Spectrometry, Revision 3,
February 2007, in EPA Publication No.
SW–846, Test Methods for Evaluating
Solid Waste, Physical/Chemical
Methods, Third Edition, IBR approved
for table 6 to subpart DDDDD.
(19) Method 7060A (SW–846–7060A),
Arsenic (Atomic Absorption, Furnace
Technique), Revision 1, September
1994, in EPA Publication No. SW–846,
Test Methods for Evaluating Solid
Waste, Physical/Chemical Methods,
Third Edition, IBR approved for table 6
to subpart DDDDD.
(20) Method 7740 (SW–846–7740),
Selenium (Atomic Absorption, Furnace
Technique), Revision 0, September
1986, in EPA Publication No. SW–846,
Test Methods for Evaluating Solid
Waste, Physical/Chemical Methods,
Third Edition, IBR approved for table 6
to subpart DDDDD.
*
*
*
*
*
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(r) The following material is available
for purchase from the Technical
Association of the Pulp and Paper
Industry (TAPPI), 15 Technology
Parkway South, Norcross, GA 30092,
(800) 332–8686, https://www.tappi.org.
(1) TAPPI T 266, Determination of
Sodium, Calcium, Copper, Iron, and
Manganese in Pulp and Paper by
Atomic Absorption Spectroscopy
(Reaffirmation of T 266 om-02), Draft
No. 2, July 2006, IBR approved for table
6 to subpart DDDDD.
(2) [Reserved]
Subpart DDDDD—[Amended]
4. Section 63.7485 is revised to read
as follows:
■
§ 63.7485
Am I subject to this subpart?
You are subject to this subpart if you
own or operate an industrial,
commercial, or institutional boiler or
process heater as defined in § 63.7575
that is located at, or is part of, a major
source of HAP, except as specified in
§ 63.7491. For purposes of this subpart,
a major source of HAP is as defined in
§ 63.2, except that for oil and natural gas
production facilities, a major source of
HAP is as defined in § 63.7575.
■ 5. Section 63.7490 is amended by
adding paragraph (e) to read as follows:
§ 63.7490 What is the affected source of
this subpart?
*
*
*
*
*
(e) An existing electric utility steam
generating unit (EGU) that meets the
applicability requirements of this
subpart after the effective date of this
final rule due to a change (e.g., fuel
switch) is considered to be an existing
source under this subpart.
■ 6. Section 63.7491 is amended by:
■ a. Revising the introductory text.
■ b. Revising paragraph (a).
■ c. Revising paragraph (c).
■ d. Revising paragraph (h)
■ e. Revising paragraph (i).
■ f. Revising paragraph (m).
■ g. Revising paragraph (n).
The revisions read as follows:
§ 63.7491 Are any boilers or process
heaters not subject to this subpart?
The types of boilers and process
heaters listed in paragraphs (a) through
(n) of this section are not subject to this
subpart.
(a) An electric utility steam generating
unit (EGU) covered by subpart UUUUU
of this part.
*
*
*
*
*
(c) A boiler or process heater that is
used specifically for research and
development, including test steam
boilers used to provide steam for testing
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the propulsion systems on military
vessels. This does not include units that
provide heat or steam to a process at a
research and development facility.
*
*
*
*
*
(h) Any boiler or process heater that
is part of the affected source subject to
another subpart of this part, such as
boilers and process heaters used as
control devices to comply with subparts
JJJ, OOO, PPP, and U of this part.
(i) Any boiler or process heater that is
used as a control device to comply with
another subpart of this part, or part 60,
part 61, or part 65 of this chapter
provided that at least 50 percent of the
average annual heat input during any 3
consecutive calendar years to the boiler
or process heater is provided by
regulated gas streams that are subject to
another standard.
*
*
*
*
*
(m) A unit that burns hazardous waste
covered by Subpart EEE of this part. A
unit that is exempt from Subpart EEE as
specified in § 63.1200(b) is not covered
by Subpart EEE.
(n) Residential boilers as defined in
this subpart.
*
*
*
*
*
■ 7. Section 63.7495 is amended by:
■ a. Revising paragraph (a).
■ b. Revising paragraph (b).
■ c. Adding paragraphs (e), (f), and (g).
The revisions and additions read as
follows:
§ 63.7495 When do I have to comply with
this subpart?
(a) If you have a new or reconstructed
boiler or process heater, you must
comply with this subpart by January 31,
2013, or upon startup of your boiler or
process heater, whichever is later.
(b) If you have an existing boiler or
process heater, you must comply with
this subpart no later than January 31,
2016, except as provided in § 63.6(i).
*
*
*
*
*
(e) If you own or operate an
industrial, commercial, or institutional
boiler or process heater and would be
subject to this subpart except for the
exemption in § 63.7491(l) for
commercial and industrial solid waste
incineration units covered by part 60,
subpart CCCC or subpart DDDD, and
you cease combusting solid waste, you
must be in compliance with this subpart
and are no longer subject to part 60,
subparts CCCC or DDDD beginning on
the effective date of the switch as
identified under the provisions of
§ 60.2145(a)(2) and (3) or § 60.2710(a)(2)
and (3).
(f) If you own or operate an existing
EGU that becomes subject to this
subpart after January 31, 2013, you must
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be in compliance with the applicable
existing source provisions of this
subpart on the effective date such unit
becomes subject to this subpart.
(g) If you own or operate an existing
industrial, commercial, or institutional
boiler or process heater and would be
subject to this subpart except for a
exemption in § 63.7491(i) that becomes
subject to this subpart after January 31,
2013, you must be in compliance with
the applicable existing source
provisions of this subpart within 3 years
after such unit becomes subject to this
subpart.
■ 8.Section 63.7499 is amended by
revising paragraphs (d) and (f) through
(l) and adding paragraphs (p) through
(u) to read as follows:
§ 63.7499 What are the subcategories of
boilers and process heaters?
*
*
*
*
*
(d) Stokers/sloped grate/other units
designed to burn kiln dried biomass/
bio-based solid.
*
*
*
*
*
(f) Suspension burners designed to
burn biomass/bio-based solid.
(g) Fuel cells designed to burn
biomass/bio-based solid.
(h) Hybrid suspension/grate burners
designed to burn wet biomass/bio-based
solid.
(i) Stokers/sloped grate/other units
designed to burn wet biomass/bio-based
solid.
(j) Dutch ovens/pile burners designed
to burn biomass/bio-based solid.
(k) Units designed to burn liquid fuel
that are non-continental units.
(l) Units designed to burn gas 1 fuels.
*
*
*
*
*
(p) Units designed to burn solid fuel.
(q) Units designed to burn liquid fuel.
(r) Units designed to burn coal/solid
fossil fuel.
(s) Fluidized bed units with an
integrated fluidized bed heat exchanger
designed to burn coal/solid fossil fuel.
(t) Units designed to burn heavy
liquid fuel.
(u) Units designed to burn light liquid
fuel.
■ 9. Section 63.7500 is amended by:
■ a. Revising paragraph (a).
■ b. Revising paragraph (c).
■ c. Adding paragraph (d).
■ d. Adding paragraph (e).
■ e. Adding paragraph (f).
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§ 63.7500 What emission limitations, work
practice standards, and operating limits
must I meet?
(a) You must meet the requirements in
paragraphs (a)(1) through (3) of this
section, except as provided in
paragraphs (b), through (e) of this
section. You must meet these
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requirements at all times the affected
unit is operating, except as provided in
paragraph (f) of this section.
(1) You must meet each emission
limit and work practice standard in
Tables 1 through 3, and 11 through 13
to this subpart that applies to your
boiler or process heater, for each boiler
or process heater at your source, except
as provided under § 63.7522. The
output-based emission limits, in units of
pounds per million Btu of steam output,
in Tables 1 or 2 to this subpart are an
alternative applicable only to boilers
and process heaters that generate steam.
The output-based emission limits, in
units of pounds per megawatt-hour, in
Tables 1 or 2 to this subpart are an
alternative applicable only to boilers
that generate electricity. If you operate
a new boiler or process heater, you can
choose to comply with alternative limits
as discussed in paragraphs (a)(1)(i)
through (a)(1)(iii) of this section, but on
or after January 31, 2016, you must
comply with the emission limits in
Table 1 to this subpart.
(i) If your boiler or process heater
commenced construction or
reconstruction after June 4, 2010 and
before May 20, 2011, you may comply
with the emission limits in Table 1 or
11 to this subpart until January 31,
2016.
(ii) If your boiler or process heater
commenced construction or
reconstruction after May 20, 2011 and
before December 23, 2011, you may
comply with the emission limits in
Table 1 or 12 to this subpart until
January 31, 2016.
(iii) If your boiler or process heater
commenced construction or
reconstruction after December 23, 2011
and before January 31, 2013, you may
comply with the emission limits in
Table 1 or 13 to this subpart until
January 31, 2016.
(2) You must meet each operating
limit in Table 4 to this subpart that
applies to your boiler or process heater.
If you use a control device or
combination of control devices not
covered in Table 4 to this subpart, or
you wish to establish and monitor an
alternative operating limit or an
alternative monitoring parameter, you
must apply to the EPA Administrator for
approval of alternative monitoring
under § 63.8(f).
(3) At all times, you must operate and
maintain any affected source (as defined
in § 63.7490), including associated air
pollution control equipment and
monitoring equipment, in a manner
consistent with safety and good air
pollution control practices for
minimizing emissions. Determination of
whether such operation and
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maintenance procedures are being used
will be based on information available
to the Administrator that may include,
but is not limited to, monitoring results,
review of operation and maintenance
procedures, review of operation and
maintenance records, and inspection of
the source.
*
*
*
*
*
(c) Limited-use boilers and process
heaters must complete a tune-up every
5 years as specified in § 63.7540. They
are not subject to the emission limits in
Tables 1 and 2 or 11 through 13 to this
subpart, the annual tune-up, or the
energy assessment requirements in
Table 3 to this subpart, or the operating
limits in Table 4 to this subpart.
(d) Boilers and process heaters with a
heat input capacity of less than or equal
to 5 million Btu per hour in the units
designed to burn gas 2 (other) fuels
subcategory or units designed to burn
light liquid fuels subcategory must
complete a tune-up every 5 years as
specified in § 63.7540.
(e) Boilers and process heaters in the
units designed to burn gas 1 fuels
subcategory with a heat input capacity
of less than or equal to 5 million Btu per
hour must complete a tune-up every 5
years as specified in § 63.7540. Boilers
and process heaters in the units
designed to burn gas 1 fuels subcategory
with a heat input capacity greater than
5 million Btu per hour and less than 10
million Btu per hour must complete a
tune-up every 2 years as specified in
§ 63.7540. Boilers and process heaters in
the units designed to burn gas 1 fuels
subcategory are not subject to the
emission limits in Tables 1 and 2 or 11
through 13 to this subpart, or the
operating limits in Table 4 to this
subpart.
(f) These standards apply at all times
the affected unit is operating, except
during periods of startup and shutdown
during which time you must comply
only with Table 3 to this subpart.
■ 10. Section 63.7501 is revised to read
as follows:
§ 63.7501 Affirmative Defense for Violation
of Emission Standards During Malfunction.
In response to an action to enforce the
standards set forth in § 63.7500 you may
assert an affirmative defense to a claim
for civil penalties for violations of such
standards that are caused by
malfunction, as defined at § 63.2.
Appropriate penalties may be assessed
if you fail to meet your burden of
proving all of the requirements in the
affirmative defense. The affirmative
defense shall not be available for claims
for injunctive relief.
(a) Assertion of affirmative defense.
To establish the affirmative defense in
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any action to enforce such a standard,
you must timely meet the reporting
requirements in paragraph (b) of this
section, and must prove by a
preponderance of evidence that:
(1) The violation:
(i) Was caused by a sudden,
infrequent, and unavoidable failure of
air pollution control equipment, process
equipment, or a process to operate in a
normal or usual manner; and
(ii) Could not have been prevented
through careful planning, proper design,
or better operation and maintenance
practices; and
(iii) Did not stem from any activity or
event that could have been foreseen and
avoided, or planned for; and
(iv) Was not part of a recurring pattern
indicative of inadequate design,
operation, or maintenance; and
(2) Repairs were made as
expeditiously as possible when a
violation occurred; and
(3) The frequency, amount, and
duration of the violation (including any
bypass) were minimized to the
maximum extent practicable; and
(4) If the violation resulted from a
bypass of control equipment or a
process, then the bypass was
unavoidable to prevent loss of life,
personal injury, or severe property
damage; and
(5) All possible steps were taken to
minimize the impact of the violation on
ambient air quality, the environment,
and human health; and
(6) All emissions monitoring and
control systems were kept in operation
if at all possible, consistent with safety
and good air pollution control practices;
and
(7) All of the actions in response to
the violation were documented by
properly signed, contemporaneous
operating logs; and
(8) At all times, the affected source
was operated in a manner consistent
with good practices for minimizing
emissions; and
(9) A written root cause analysis has
been prepared, the purpose of which is
to determine, correct, and eliminate the
primary causes of the malfunction and
the violation resulting from the
malfunction event at issue. The analysis
shall also specify, using best monitoring
methods and engineering judgment, the
amount of any emissions that were the
result of the malfunction.
(b) Report. The owner or operator
seeking to assert an affirmative defense
shall submit a written report to the
Administrator with all necessary
supporting documentation, that it has
met the requirements set forth in
§ 63.7500 of this section. This
affirmative defense report shall be
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included in the first periodic
compliance, deviation report or excess
emission report otherwise required after
the initial occurrence of the violation of
the relevant standard (which may be the
end of any applicable averaging period).
If such compliance, deviation report or
excess emission report is due less than
45 days after the initial occurrence of
the violation, the affirmative defense
report may be included in the second
compliance, deviation report or excess
emission report due after the initial
occurrence of the violation of the
relevant standard.
■ 11. Section 63.7505 is amended by:
■ a. Revising paragraph (a).
■ b. Revising paragraph (c).
■ c. Revising paragraphs (d)
introductory text, (d)(1) introductory
text, and (d)(1)(iii).
§ 63.7505 What are my general
requirements for complying with this
subpart?
(a) You must be in compliance with
the emission limits, work practice
standards, and operating limits in this
subpart. These limits apply to you at all
times the affected unit is operating
except for the periods noted in
§ 63.7500(f).
*
*
*
*
*
(c) You must demonstrate compliance
with all applicable emission limits
using performance stack testing, fuel
analysis, or continuous monitoring
systems (CMS), including a continuous
emission monitoring system (CEMS),
continuous opacity monitoring system
(COMS), continuous parameter
monitoring system (CPMS), or
particulate matter continuous parameter
monitoring system (PM CPMS), where
applicable. You may demonstrate
compliance with the applicable
emission limit for hydrogen chloride
(HCl), mercury, or total selected metals
(TSM) using fuel analysis if the
emission rate calculated according to
§ 63.7530(c) is less than the applicable
emission limit. (For gaseous fuels, you
may not use fuel analyses to comply
with the TSM alternative standard or
the HCl standard.) Otherwise, you must
demonstrate compliance for HCl,
mercury, or TSM using performance
testing, if subject to an applicable
emission limit listed in Tables 1, 2, or
11 through 13 to this subpart.
(d) If you demonstrate compliance
with any applicable emission limit
through performance testing and
subsequent compliance with operating
limits (including the use of CPMS), or
with a CEMS, or COMS, you must
develop a site-specific monitoring plan
according to the requirements in
paragraphs (d)(1) through (4) of this
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section for the use of any CEMS, COMS,
or CPMS. This requirement also applies
to you if you petition the EPA
Administrator for alternative monitoring
parameters under § 63.8(f).
(1) For each CMS required in this
section (including CEMS, COMS, or
CPMS), you must develop, and submit
to the Administrator for approval upon
request, a site-specific monitoring plan
that addresses design, data collection,
and the quality assurance and quality
control elements outlined in § 63.8(d)
and the elements described in
paragraphs (d)(1)(i) through (iii) of this
section. You must submit this sitespecific monitoring plan, if requested, at
least 60 days before your initial
performance evaluation of your CMS.
This requirement to develop and submit
a site specific monitoring plan does not
apply to affected sources with existing
CEMS or COMS operated according to
the performance specifications under
appendix B to part 60 of this chapter
and that meet the requirements of
§ 63.7525. Using the process described
in § 63.8(f)(4), you may request approval
of alternative monitoring system quality
assurance and quality control
procedures in place of those specified in
this paragraph and, if approved, include
the alternatives in your site-specific
monitoring plan.
*
*
*
*
*
(iii) Performance evaluation
procedures and acceptance criteria (e.g.,
calibrations, accuracy audits, analytical
drift).
*
*
*
*
*
■ 12. Section 63.7510 is revised to read
as follows:
§ 63.7510 What are my initial compliance
requirements and by what date must I
conduct them?
(a) For each boiler or process heater
that is required or that you elect to
demonstrate compliance with any of the
applicable emission limits in Tables 1 or
2 or 11 through 13 of this subpart
through performance testing, your
initial compliance requirements include
all the following:
(1) Conduct performance tests
according to § 63.7520 and Table 5 to
this subpart.
(2) Conduct a fuel analysis for each
type of fuel burned in your boiler or
process heater according to § 63.7521
and Table 6 to this subpart, except as
specified in paragraphs (a)(2)(i) through
(iii) of this section.
(i) For each boiler or process heater
that burns a single type of fuel, you are
not required to conduct a fuel analysis
for each type of fuel burned in your
boiler or process heater according to
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§ 63.7521 and Table 6 to this subpart.
For purposes of this subpart, units that
use a supplemental fuel only for startup,
unit shutdown, and transient flame
stability purposes still qualify as units
that burn a single type of fuel, and the
supplemental fuel is not subject to the
fuel analysis requirements under
§ 63.7521 and Table 6 to this subpart.
(ii) When natural gas, refinery gas, or
other gas 1 fuels are co-fired with other
fuels, you are not required to conduct a
fuel analysis of those fuels according to
§ 63.7521 and Table 6 to this subpart. If
gaseous fuels other than natural gas,
refinery gas, or other gas 1 fuels are cofired with other fuels and those gaseous
fuels are subject to another subpart of
this part, part 60, part 61, or part 65, you
are not required to conduct a fuel
analysis of those fuels according to
§ 63.7521 and Table 6 to this subpart.
(iii) You are not required to conduct
a chlorine fuel analysis for any gaseous
fuels. You must conduct a fuel analysis
for mercury on gaseous fuels unless the
fuel is exempted in paragraphs (a)(2)(i)
and (ii) of this section.
(3) Establish operating limits
according to § 63.7530 and Table 7 to
this subpart.
(4) Conduct CMS performance
evaluations according to § 63.7525.
(b) For each boiler or process heater
that you elect to demonstrate
compliance with the applicable
emission limits in Tables 1 or 2 or 11
through 13 to this subpart for HCl,
mercury, or TSM through fuel analysis,
your initial compliance requirement is
to conduct a fuel analysis for each type
of fuel burned in your boiler or process
heater according to § 63.7521 and Table
6 to this subpart and establish operating
limits according to § 63.7530 and Table
8 to this subpart. The fuels described in
paragraph (a)(2)(i) and (ii) of this section
are exempt from these fuel analysis and
operating limit requirements. The fuels
described in paragraph (a)(2)(ii) of this
section are exempt from the chloride
fuel analysis and operating limit
requirements. Boilers and process
heaters that use a CEMS for mercury or
HCl are exempt from the performance
testing and operating limit requirements
specified in paragraph (a) of this section
for the HAP for which CEMS are used.
(c) If your boiler or process heater is
subject to a carbon monoxide (CO) limit,
your initial compliance demonstration
for CO is to conduct a performance test
for CO according to Table 5 to this
subpart or conduct a performance
evaluation of your continuous CO
monitor, if applicable, according to
§ 63.7525(a). Boilers and process heaters
that use a CO CEMS to comply with the
applicable alternative CO CEMS
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emission standard listed in Tables 12, or
11 through 13 to this subpart, as
specified in § 63.7525(a), are exempt
from the initial CO performance testing
and oxygen concentration operating
limit requirements specified in
paragraph (a) of this section.
(d) If your boiler or process heater is
subject to a PM limit, your initial
compliance demonstration for PM is to
conduct a performance test in
accordance with § 63.7520 and Table 5
to this subpart.
(e) For existing affected sources (as
defined in § 63.7490), you must
complete the initial compliance
demonstration, as specified in
paragraphs (a) through (d) of this
section, no later than 180 days after the
compliance date that is specified for
your source in § 63.7495 and according
to the applicable provisions in
§ 63.7(a)(2) as cited in Table 10 to this
subpart, except as specified in
paragraph (j) of this section. You must
complete an initial tune-up by following
the procedures described in
§ 63.7540(a)(10)(i) through (vi) no later
than the compliance date specified in
§ 63.7495, except as specified in
paragraph (j) of this section. You must
complete the one-time energy
assessment specified in Table 3 to this
subpart no later than the compliance
date specified in § 63.7495, except as
specified in paragraph (j) of this section.
(f) For new or reconstructed affected
sources (as defined in § 63.7490), you
must complete the initial compliance
demonstration with the emission limits
no later than July 30, 2013 or within 180
days after startup of the source,
whichever is later. If you are
demonstrating compliance with an
emission limit in Tables 11 through 13
to this subpart that is less stringent (that
is, higher) than the applicable emission
limit in Table 1 to this subpart, you
must demonstrate compliance with the
applicable emission limit in Table 1 no
later than July 29, 2016.
(g) For new or reconstructed affected
sources (as defined in § 63.7490), you
must demonstrate initial compliance
with the applicable work practice
standards in Table 3 to this subpart
within the applicable annual, biennial,
or 5-year schedule as specified in
§ 63.7540(a) following the initial
compliance date specified in
§ 63.7495(a). Thereafter, you are
required to complete the applicable
annual, biennial, or 5-year tune-up as
specified in § 63.7540(a).
(h) For affected sources (as defined in
§ 63.7490) that ceased burning solid
waste consistent with § 63.7495(e) and
for which the initial compliance date
has passed, you must demonstrate
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compliance within 60 days of the
effective date of the waste-to-fuel
switch. If you have not conducted your
compliance demonstration for this
subpart within the previous 12 months,
you must complete all compliance
demonstrations for this subpart before
you commence or recommence
combustion of solid waste.
(i) For an existing EGU that becomes
subject after January 31, 2013, you must
demonstrate compliance within 180
days after becoming an affected source.
(j) For existing affected sources (as
defined in § 63.7490) that have not
operated between the effective date of
the rule and the compliance date that is
specified for your source in § 63.7495,
you must complete the initial
compliance demonstration, if subject to
the emission limits in Table 2 to this
subpart, as specified in paragraphs (a)
through (d) of this section, no later than
180 days after the re-start of the affected
source and according to the applicable
provisions in § 63.7(a)(2) as cited in
Table 10 to this subpart. You must
complete an initial tune-up by following
the procedures described in
§ 63.7540(a)(10)(i) through (vi) no later
than 30 days after the re-start of the
affected source and, if applicable,
complete the one-time energy
assessment specified in Table 3 to this
subpart, no later than the compliance
date specified in § 63.7495.
■ 13. Section 63.7515 is revised to read
as follows:
§ 63.7515 When must I conduct
subsequent performance tests, fuel
analyses, or tune-ups?
(a) You must conduct all applicable
performance tests according to § 63.7520
on an annual basis, except as specified
in paragraphs (b) through (e), (g), and (h)
of this section. Annual performance
tests must be completed no more than
13 months after the previous
performance test, except as specified in
paragraphs (b) through (e), (g), and (h)
of this section.
(b) If your performance tests for a
given pollutant for at least 2 consecutive
years show that your emissions are at or
below 75 percent of the emission limit
(or, in limited instances as specified in
Tables 1 and 2 or 11 through 13 to this
subpart, at or below the emission limit)
for the pollutant, and if there are no
changes in the operation of the
individual boiler or process heater or air
pollution control equipment that could
increase emissions, you may choose to
conduct performance tests for the
pollutant every third year. Each such
performance test must be conducted no
more than 37 months after the previous
performance test. If you elect to
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demonstrate compliance using emission
averaging under § 63.7522, you must
continue to conduct performance tests
annually. The requirement to test at
maximum chloride input level is
waived unless the stack test is
conducted for HCl. The requirement to
test at maximum mercury input level is
waived unless the stack test is
conducted for mercury. The
requirement to test at maximum TSM
input level is waived unless the stack
test is conducted for TSM.
(c) If a performance test shows
emissions exceeded the emission limit
or 75 percent of the emission limit (as
specified in Tables 1 and 2 or 11
through 13 to this subpart) for a
pollutant, you must conduct annual
performance tests for that pollutant
until all performance tests over a
consecutive 2-year period meet the
required level (at or below 75 percent of
the emission limit, as specified in
Tables 1 and 2 or 11 through 13 to this
subpart).
(d) If you are required to meet an
applicable tune-up work practice
standard, you must conduct an annual,
biennial, or 5-year performance tune-up
according to § 63.7540(a)(10), (11), or
(12), respectively. Each annual tune-up
specified in § 63.7540(a)(10) must be no
more than 13 months after the previous
tune-up. Each biennial tune-up
specified in § 63.7540(a)(11) must be
conducted no more than 25 months after
the previous tune-up. Each 5-year tuneup specified in § 63.7540(a)(12) must be
conducted no more than 61 months after
the previous tune-up. For a new or
reconstructed affected source (as
defined in § 63.7490), the first annual,
biennial, or 5-year tune-up must be no
later than 13 months, 25 months, or 61
months, respectively, after the initial
startup of the new or reconstructed
affected source.
(e) If you demonstrate compliance
with the mercury, HCl, or TSM based on
fuel analysis, you must conduct a
monthly fuel analysis according to
§ 63.7521 for each type of fuel burned
that is subject to an emission limit in
Tables 1, 2, or 11 through 13 to this
subpart. You may comply with this
monthly requirement by completing the
fuel analysis any time within the
calendar month as long as the analysis
is separated from the previous analysis
by at least 14 calendar days. If you burn
a new type of fuel, you must conduct a
fuel analysis before burning the new
type of fuel in your boiler or process
heater. You must still meet all
applicable continuous compliance
requirements in § 63.7540. If each of 12
consecutive monthly fuel analyses
demonstrates 75 percent or less of the
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compliance level, you may decrease the
fuel analysis frequency to quarterly for
that fuel. If any quarterly sample
exceeds 75 percent of the compliance
level or you begin burning a new type
of fuel, you must return to monthly
monitoring for that fuel, until 12 months
of fuel analyses are again less than 75
percent of the compliance level.
(f) You must report the results of
performance tests and the associated
fuel analyses within 60 days after the
completion of the performance tests.
This report must also verify that the
operating limits for each boiler or
process heater have not changed or
provide documentation of revised
operating limits established according to
§ 63.7530 and Table 7 to this subpart, as
applicable. The reports for all
subsequent performance tests must
include all applicable information
required in § 63.7550.
(g) For affected sources (as defined in
§ 63.7490) that have not operated since
the previous compliance demonstration
and more than one year has passed
since the previous compliance
demonstration, you must complete the
subsequent compliance demonstration,
if subject to the emission limits in
Tables 1, 2, or 11 through 13 to this
subpart, no later than 180 days after the
re-start of the affected source and
according to the applicable provisions
in § 63.7(a)(2) as cited in Table 10 to this
subpart. You must complete a
subsequent tune-up by following the
procedures described in
§ 63.7540(a)(10)(i) through (vi) and the
schedule described in § 63.7540(a)(13)
for units that are not operating at the
time of their scheduled tune-up.
(h) If your affected boiler or process
heater is in the unit designed to burn
light liquid subcategory and you
combust ultra low sulfur liquid fuel,
you do not need to conduct further
performance tests if the pollutants
measured during the initial compliance
performance tests meet the emission
limits in Tables 1 or 2 of this subpart
providing you demonstrate ongoing
compliance with the emissions limits by
monitoring and recording the type of
fuel combusted on a monthly basis. If
you intend to use a fuel other than ultra
low sulfur liquid fuel, natural gas,
refinery gas, or other gas 1 fuel, you
must conduct new performance tests
within 60 days of burning the new fuel
type.
(i) If you operate a CO CEMS that
meets the Performance Specifications
outlined in § 63.7525(a)(3) of this
subpart to demonstrate compliance with
the applicable alternative CO CEMS
emission standard listed in Tables 1, 2,
or 11 through 13 to this subpart, you are
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not required to conduct CO performance
tests and are not subject to the oxygen
concentration operating limit
requirement specified in § 63.7510(a).
■ 14. Section § 63.7520 is amended by
revising paragraphs (a), (c), (d), and (e)
and adding paragraph (f) to read as
follows:
§ 63.7520 What stack tests and procedures
must I use?
(a) You must conduct all performance
tests according to § 63.7(c), (d), (f), and
(h). You must also develop a sitespecific stack test plan according to the
requirements in § 63.7(c). You shall
conduct all performance tests under
such conditions as the Administrator
specifies to you based on the
representative performance of each
boiler or process heater for the period
being tested. Upon request, you shall
make available to the Administrator
such records as may be necessary to
determine the conditions of the
performance tests.
*
*
*
*
*
(c) You must conduct each
performance test under the specific
conditions listed in Tables 5 and 7 to
this subpart. You must conduct
performance tests at representative
operating load conditions while burning
the type of fuel or mixture of fuels that
has the highest content of chlorine and
mercury, and TSM if you are opting to
comply with the TSM alternative
standard and you must demonstrate
initial compliance and establish your
operating limits based on these
performance tests. These requirements
could result in the need to conduct
more than one performance test.
Following each performance test and
until the next performance test, you
must comply with the operating limit
for operating load conditions specified
in Table 4 to this subpart.
(d) You must conduct a minimum of
three separate test runs for each
performance test required in this
section, as specified in § 63.7(e)(3). Each
test run must comply with the
minimum applicable sampling times or
volumes specified in Tables 1 and 2 or
11 through 13 to this subpart.
(e) To determine compliance with the
emission limits, you must use the FFactor methodology and equations in
sections 12.2 and 12.3 of EPA Method
19 at 40 CFR part 60, appendix A–7 of
this chapter to convert the measured
particulate matter (PM) concentrations,
the measured HCl concentrations, the
measured mercury concentrations, and
the measured TSM concentrations that
result from the performance test to
pounds per million Btu heat input
emission rates.
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(f) Except for a 30-day rolling average
based on CEMS (or sorbent trap
monitoring system) data, if
measurement results for any pollutant
are reported as below the method
detection level (e.g., laboratory
analytical results for one or more
sample components are below the
method defined analytical detection
level), you must use the method
detection level as the measured
emissions level for that pollutant in
calculating compliance. The measured
result for a multiple component analysis
(e.g., analytical values for multiple
Method 29 fractions both for individual
HAP metals and for total HAP metals)
may include a combination of method
detection level data and analytical data
reported above the method detection
level.
■ 15. Section 63.7521 is revised to read
as follows:
tkelley on DSK3SPTVN1PROD with
§ 63.7521 What fuel analyses, fuel
specification, and procedures must I use?
(a) For solid and liquid fuels, you
must conduct fuel analyses for chloride
and mercury according to the
procedures in paragraphs (b) through (e)
of this section and Table 6 to this
subpart, as applicable. For solid fuels
and liquid fuels, you must also conduct
fuel analyses for TSM if you are opting
to comply with the TSM alternative
standard. For gas 2 (other) fuels, you
must conduct fuel analyses for mercury
according to the procedures in
paragraphs (b) through (e) of this section
and Table 6 to this subpart, as
applicable. (For gaseous fuels, you may
not use fuel analyses to comply with the
TSM alternative standard or the HCl
standard.) For purposes of complying
with this section, a fuel gas system that
consists of multiple gaseous fuels
collected and mixed with each other is
considered a single fuel type and
sampling and analysis is only required
on the combined fuel gas system that
will feed the boiler or process heater.
Sampling and analysis of the individual
gaseous streams prior to combining is
not required. You are not required to
conduct fuel analyses for fuels used for
only startup, unit shutdown, and
transient flame stability purposes. You
are required to conduct fuel analyses
only for fuels and units that are subject
to emission limits for mercury, HCl, or
TSM in Tables 1 and 2 or 11 through 13
to this subpart. Gaseous and liquid fuels
are exempt from the sampling
requirements in paragraphs (c) and (d)
of this section and Table 6 to this
subpart.
(b) You must develop a site-specific
fuel monitoring plan according to the
following procedures and requirements
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in paragraphs (b)(1) and (2) of this
section, if you are required to conduct
fuel analyses as specified in § 63.7510.
(1) If you intend to use an alternative
analytical method other than those
required by Table 6 to this subpart, you
must submit the fuel analysis plan to
the Administrator for review and
approval no later than 60 days before
the date that you intend to conduct the
initial compliance demonstration
described in § 63.7510.
(2) You must include the information
contained in paragraphs (b)(2)(i)
through (vi) of this section in your fuel
analysis plan.
(i) The identification of all fuel types
anticipated to be burned in each boiler
or process heater.
(ii) For each anticipated fuel type, the
notification of whether you or a fuel
supplier will be conducting the fuel
analysis.
(iii) For each anticipated fuel type, a
detailed description of the sample
location and specific procedures to be
used for collecting and preparing the
composite samples if your procedures
are different from paragraph (c) or (d) of
this section. Samples should be
collected at a location that most
accurately represents the fuel type,
where possible, at a point prior to
mixing with other dissimilar fuel types.
(iv) For each anticipated fuel type, the
analytical methods from Table 6, with
the expected minimum detection levels,
to be used for the measurement of
chlorine or mercury.
(v) If you request to use an alternative
analytical method other than those
required by Table 6 to this subpart, you
must also include a detailed description
of the methods and procedures that you
are proposing to use. Methods in Table
6 shall be used until the requested
alternative is approved.
(vi) If you will be using fuel analysis
from a fuel supplier in lieu of sitespecific sampling and analysis, the fuel
supplier must use the analytical
methods required by Table 6 to this
subpart.
(c) At a minimum, you must obtain
three composite fuel samples for each
fuel type according to the procedures in
paragraph (c)(1) or (2) of this section, or
the methods listed in Table 6 to this
subpart, or use an automated sampling
mechanism that provides representative
composite fuel samples for each fuel
type that includes both coarse and fine
material.
(1) If sampling from a belt (or screw)
feeder, collect fuel samples according to
paragraphs (c)(1)(i) and (ii) of this
section.
(i) Stop the belt and withdraw a 6inch wide sample from the full cross-
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7167
section of the stopped belt to obtain a
minimum two pounds of sample. You
must collect all the material (fines and
coarse) in the full cross-section. You
must transfer the sample to a clean
plastic bag.
(ii) Each composite sample will
consist of a minimum of three samples
collected at approximately equal onehour intervals during the testing period
for sampling during performance stack
testing. For monthly sampling, each
composite sample shall be collected at
approximately equal 10-day intervals
during the month.
(2) If sampling from a fuel pile or
truck, you must collect fuel samples
according to paragraphs (c)(2)(i) through
(iii) of this section.
(i) For each composite sample, you
must select a minimum of five sampling
locations uniformly spaced over the
surface of the pile.
(ii) At each sampling site, you must
dig into the pile to a uniform depth of
approximately 18 inches. You must
insert a clean shovel into the hole and
withdraw a sample, making sure that
large pieces do not fall off during
sampling; use the same shovel to collect
all samples.
(iii) You must transfer all samples to
a clean plastic bag for further
processing.
(d) You must prepare each composite
sample according to the procedures in
paragraphs (d)(1) through (7) of this
section.
(1) You must thoroughly mix and
pour the entire composite sample over
a clean plastic sheet.
(2) You must break large sample
pieces (e.g., larger than 3 inches) into
smaller sizes.
(3) You must make a pie shape with
the entire composite sample and
subdivide it into four equal parts.
(4) You must separate one of the
quarter samples as the first subset.
(5) If this subset is too large for
grinding, you must repeat the procedure
in paragraph (d)(3) of this section with
the quarter sample and obtain a onequarter subset from this sample.
(6) You must grind the sample in a
mill.
(7) You must use the procedure in
paragraph (d)(3) of this section to obtain
a one-quarter subsample for analysis. If
the quarter sample is too large,
subdivide it further using the same
procedure.
(e) You must determine the
concentration of pollutants in the fuel
(mercury and/or chlorine and/or TSM)
in units of pounds per million Btu of
each composite sample for each fuel
type according to the procedures in
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Table 6 to this subpart, for use in
Equations 7, 8, and 9 of this subpart.
(f) To demonstrate that a gaseous fuel
other than natural gas or refinery gas
qualifies as an other gas 1 fuel, as
defined in § 63.7575, you must conduct
a fuel specification analyses for mercury
according to the procedures in
paragraphs (g) through (i) of this section
and Table 6 to this subpart, as
applicable, except as specified in
paragraph (f)(1) through (4) of this
section.
(1) You are not required to conduct
the fuel specification analyses in
paragraphs (g) through (i) of this section
for natural gas or refinery gas.
(2) You are not required to conduct
the fuel specification analyses in
paragraphs (g) through (i) of this section
for gaseous fuels that are subject to
another subpart of this part, part 60, part
61, or part 65.
(3) You are not required to conduct
the fuel specification analyses in
paragraphs (g) through (i) of this section
on gaseous fuels for units that are
complying with the limits for units
designed to burn gas 2 (other) fuels.
(4) You are not required to conduct
the fuel specification analyses in
paragraphs (g) through (i) of this section
for gas streams directly derived from
natural gas at natural gas production
sites or natural gas plants.
(g) You must develop and submit a
site-specific fuel analysis plan for other
gas 1 fuels to the EPA Administrator for
review and approval according to the
following procedures and requirements
in paragraphs (g)(1) and (2) of this
section.
(1) If you intend to use an alternative
analytical method other than those
required by Table 6 to this subpart, you
must submit the fuel analysis plan to
the Administrator for review and
approval no later than 60 days before
the date that you intend to conduct the
initial compliance demonstration
described in § 63.7510.
(2) You must include the information
contained in paragraphs (g)(2)(i) through
(vi) of this section in your fuel analysis
plan.
(i) The identification of all gaseous
fuel types other than those exempted
from fuel specification analysis under
(f)(1) through (3) of this section
anticipated to be burned in each boiler
or process heater.
(ii) For each anticipated fuel type, the
notification of whether you or a fuel
supplier will be conducting the fuel
specification analysis.
(iii) For each anticipated fuel type, a
detailed description of the sample
location and specific procedures to be
used for collecting and preparing the
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Jkt 229001
samples if your procedures are different
from the sampling methods contained in
Table 6 to this subpart. Samples should
be collected at a location that most
accurately represents the fuel type,
where possible, at a point prior to
mixing with other dissimilar fuel types.
If multiple boilers or process heaters are
fueled by a common fuel stream it is
permissible to conduct a single gas
specification at the common point of gas
distribution.
(iv) For each anticipated fuel type, the
analytical methods from Table 6 to this
subpart, with the expected minimum
detection levels, to be used for the
measurement of mercury.
(v) If you request to use an alternative
analytical method other than those
required by Table 6 to this subpart, you
must also include a detailed description
of the methods and procedures that you
are proposing to use. Methods in Table
6 to this subpart shall be used until the
requested alternative is approved.
(vi) If you will be using fuel analysis
from a fuel supplier in lieu of sitespecific sampling and analysis, the fuel
supplier must use the analytical
methods required by Table 6 to this
subpart.
(h) You must obtain a single fuel
sample for each fuel type according to
the sampling procedures listed in Table
6 for fuel specification of gaseous fuels.
(i) You must determine the
concentration in the fuel of mercury, in
units of microgram per cubic meter, dry
basis, of each sample for each other gas
1 fuel type according to the procedures
in Table 6 to this subpart.
■ 16. Section § 63.7522 is revised by:
■ a. Revising paragraphs (a) through (d).
■ b. Revising paragraphs (e)(1) and (2).
■ c. Revising paragraphs (f) introductory
text and (f)(1) and (2).
■ d. Revising paragraphs (g)
introductory text, (g)(2)(i), (g)(2)(iv),
(g)(2)(vi)(B), (g)(3) introductory text,
(g)(4) introductory text, and (g)(4)(ii).
■ e. Revising paragraph (h).
■ f. Revising paragraph (i).
■ g. Revising paragraph (j)(1).
■ h. Revising paragraph (k).
The revisions read as follows:
§ 63.7522 Can I use emissions averaging
to comply with this subpart?
(a) As an alternative to meeting the
requirements of § 63.7500 for PM (or
TSM), HCl, or mercury on a boiler or
process heater-specific basis, if you have
more than one existing boiler or process
heater in any subcategories located at
your facility, you may demonstrate
compliance by emissions averaging, if
your averaged emissions are not more
than 90 percent of the applicable
emission limit, according to the
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procedures in this section. You may not
include new boilers or process heaters
in an emissions average.
(b) For a group of two or more existing
boilers or process heaters in the same
subcategory that each vent to a separate
stack, you may average PM (or TSM),
HCl, or mercury emissions among
existing units to demonstrate
compliance with the limits in Table 2 to
this subpart as specified in paragraph
(b)(1) through (3) of this section, if you
satisfy the requirements in paragraphs
(c) through (g) of this section.
(1) You may average units using a
CEMS or PM CPMS for demonstrating
compliance.
(2) For mercury and HCl, averaging is
allowed as follows:
(i) You may average among units in
any of the solid fuel subcategories.
(ii) You may average among units in
any of the liquid fuel subcategories.
(iii) You may average among units in
a subcategory of units designed to burn
gas 2 (other) fuels.
(iv) You may not average across the
units designed to burn liquid, units
designed to burn solid fuel, and units
designed to burn gas 2 (other)
subcategories.
(3) For PM (or TSM), averaging is only
allowed between units within each of
the following subcategories and you
may not average across subcategories:
(i) Units designed to burn coal/solid
fossil fuel.
(ii) Stokers/sloped grate/other units
designed to burn kiln dried biomass/
bio-based solids.
(iii) Stokers/sloped grate/other units
designed to burn wet biomass/bio-based
solids.
(iv) Fluidized bed units designed to
burn biomass/bio-based solid.
(v) Suspension burners designed to
burn biomass/bio-based solid.
(vi) Dutch ovens/pile burners
designed to burn biomass/bio-based
solid.
(vii) Fuel Cells designed to burn
biomass/bio-based solid.
(viii) Hybrid suspension/grate burners
designed to burn wet biomass/bio-based
solid.
(ix) Units designed to burn heavy
liquid fuel.
(x) Units designed to burn light liquid
fuel.
(xi) Units designed to burn liquid fuel
that are non-continental units.
(xii) Units designed to burn gas 2
(other) gases.
(c) For each existing boiler or process
heater in the averaging group, the
emission rate achieved during the initial
compliance test for the HAP being
averaged must not exceed the emission
level that was being achieved on
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7169
option for that pollutant do not exceed
the emission limits in Table 2 to this
subpart. Use Equation 1a if you are
complying with the emission limits on
a heat input basis, use Equation 1b if
you are complying with the emission
limits on a steam generation (output)
basis, and use Equation 1c if you are
complying with the emission limits on
a electric generation (output) basis.
Where:
AveWeightedEmissions = Average weighted
emissions for PM (or TSM), HCl, or
mercury, in units of pounds per million
Btu of steam output.
Er = Emission rate (as determined during the
initial compliance demonstration) of PM
(or TSM), HCl, or mercury from unit, i,
in units of pounds per million Btu of
steam output. Determine the emission
rate for PM (or TSM), HCl, or mercury by
performance testing according to Table 5
to this subpart, or by fuel analysis for
HCl or mercury or TSM using the
applicable equation in § 63.7530(c). If
you are taking credit for energy
conservation measures from a unit
according to § 63.7533, use the adjusted
emission level for that unit, Eadj,
determined according to § 63.7533 for
that unit.
So = Maximum steam output capacity of
unit, i, in units of million Btu per hour,
as defined in § 63.7575.
n = Number of units participating in the
emissions averaging option.
1.1 = Required discount factor.
Where:
AveWeightedEmissions = Average weighted
emissions for PM (or TSM), HCl, or
mercury, in units of pounds per
megawatt hour.
Er = Emission rate (as determined during the
initial compliance demonstration) of PM
(or TSM), HCl, or mercury from unit, i,
in units of pounds per megawatt hour.
Determine the emission rate for PM (or
TSM), HCl, or mercury by performance
testing according to Table 5 to this
subpart, or by fuel analysis for HCl or
mercury or TSM using the applicable
equation in § 63.7530(c). If you are taking
credit for energy conservation measures
from a unit according to § 63.7533, use
the adjusted emission level for that unit,
Eadj, determined according to § 63.7533
for that unit.
Eo = Maximum electric generating output
capacity of unit, i, in units of megawatt
hour, as defined in § 63.7575.
n = Number of units participating in the
emissions averaging option.
1.1 = Required discount factor.
input capacity of one or more boilers
that generate steam, you may use
Equation 2 of this section as an
alternative to using Equation 1a of this
section to demonstrate that the PM (or
TSM), HCl, or mercury emissions from
all existing units participating in the
emissions averaging option do not
exceed the emission limits for that
pollutant in Table 2 to this subpart that
are in pounds per million Btu of heat
input.
Where:
AveWeightedEmissions = Average weighted
emission level for PM (or TSM), HCl, or
mercury, in units of pounds per million
Btu of heat input.
Er = Emission rate (as determined during the
most recent compliance demonstration)
of PM (or TSM), HCl, or mercury from
unit, i, in units of pounds per million
Btu of heat input. Determine the
emission rate for PM (or TSM), HCl, or
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(2) If you are not capable of
determining the maximum rated heat
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mercury by performance testing
according to Table 5 to this subpart, or
by fuel analysis for HCl or mercury or
TSM using the applicable equation in
§ 63.7530(c).
E:\FR\FM\31JAR3.SGM
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ER31JA13.007</GPH>
HCl or mercury or TSM using the
applicable equation in § 63.7530(c).
Hm = Maximum rated heat input capacity of
unit, i, in units of million Btu per hour.
n = Number of units participating in the
emissions averaging option.
1.1 = Required discount factor.
ER31JA13.005</GPH> ER31JA13.006</GPH>
(or TSM), HCl, or mercury from unit, i,
in units of pounds per million Btu of
heat input. Determine the emission rate
for PM (or TSM), HCl, or mercury by
performance testing according to Table 5
to this subpart, or by fuel analysis for
ER31JA13.004</GPH>
the limits in Table 2 to this subpart at
all times the affected units are operating
following the compliance date specified
in § 63.7495.
(e) * * *
(1) You must use Equation 1a or 1b or
1c of this section to demonstrate that the
PM (or TSM), HCl, or mercury
emissions from all existing units
participating in the emissions averaging
Where:
AveWeightedEmissions = Average weighted
emissions for PM (or TSM), HCl, or
mercury, in units of pounds per million
Btu of heat input.
Er = Emission rate (as determined during the
initial compliance demonstration) of PM
tkelley on DSK3SPTVN1PROD with
January 31, 2013 or the control
technology employed during the initial
compliance test must not be less
effective for the HAP being averaged
than the control technology employed
on January 31, 2013.
(d) The averaged emissions rate from
the existing boilers and process heaters
participating in the emissions averaging
option must not exceed 90 percent of
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Sm = Maximum steam generation capacity by
unit, i, in units of pounds per hour.
Cfi = Conversion factor, calculated from the
most recent compliance test, in units of
million Btu of heat input per pounds of
steam generated for unit, i.
1.1 = Required discount factor.
of PM (or TSM), HCl, or mercury from
unit, i, in units of pounds per million
Btu of heat input. Determine the
emission rate for PM (or TSM), HCl, or
mercury by performance testing
according to Table 5 to this subpart, or
by fuel analysis for HCl or mercury or
TSM according to Table 6 to this subpart.
Hb = The heat input for that calendar month
to unit, i, in units of million Btu.
n = Number of units participating in the
emissions averaging option.
1.1 = Required discount factor.
Where:
AveWeightedEmissions = Average weighted
emission level for PM (or TSM), HCl, or
mercury, in units of pounds per million
Btu of steam output, for that calendar
month.
Er = Emission rate (as determined during the
most recent compliance demonstration)
of PM (or TSM), HCl, or mercury from
unit, i, in units of pounds per million
Btu of steam output. Determine the
emission rate for PM (or TSM), HCl, or
mercury by performance testing
according to Table 5 to this subpart, or
by fuel analysis for HCl or mercury or
TSM according to Table 6 to this subpart.
If you are taking credit for energy
conservation measures from a unit
according to § 63.7533, use the adjusted
emission level for that unit, Eadj,
determined according to § 63.7533 for
that unit.
So = The steam output for that calendar
month from unit, i, in units of million
Btu, as defined in § 63.7575.
n = Number of units participating in the
emissions averaging option.
1.1 = Required discount factor.
tkelley on DSK3SPTVN1PROD with
Where:
AveWeightedEmissions = Average weighted
emission level for PM (or TSM), HCl, or
mercury, in units of pounds per
megawatt hour, for that calendar month.
Er = Emission rate (as determined during the
most recent compliance demonstration)
of PM (or TSM), HCl, or mercury from
unit, i, in units of pounds per megawatt
hour. Determine the emission rate for PM
(or TSM), HCl, or mercury by
performance testing according to Table 5
to this subpart, or by fuel analysis for
HCl or mercury or TSM according to
Table 6 to this subpart. If you are taking
credit for energy conservation measures
from a unit according to § 63.7533, use
the adjusted emission level for that unit,
Eadj, determined according to § 63.7533
for that unit.
Eo = The electric generating output for that
calendar month from unit, i, in units of
megawatt hour, as defined in § 63.7575.
n = Number of units participating in the
emissions averaging option.
1.1 = Required discount factor.
(2) If you are not capable of
monitoring heat input, you may use
Equation 4 of this section as an
alternative to using Equation 3a of this
section to calculate the average
weighted emission rate using the actual
steam generation from the boilers
participating in the emissions averaging
option.
Where:
AveWeightedEmissions = average weighted
emission level for PM (or TSM), HCl, or
mercury, in units of pounds per million
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ER31JA13.009</GPH> ER31JA13.010</GPH>
Where:
AveWeightedEmissions = Average weighted
emission level for PM (or TSM), HCl, or
mercury, in units of pounds per million
Btu of heat input, for that calendar
month.
Er = Emission rate (as determined during the
most recent compliance demonstration)
(f) After the initial compliance
demonstration described in paragraph
(e) of this section, you must demonstrate
compliance on a monthly basis
determined at the end of every month
(12 times per year) according to
paragraphs (f)(1) through (3) of this
ER31JA13.011</GPH>
Use Equation 3a and the actual heat
input for the month for each existing
unit participating in the emissions
averaging option if you are complying
with emission limits on a heat input
basis. Use Equation 3b and the actual
steam generation for the month if you
are complying with the emission limits
on a steam generation (output) basis.
Use Equation 3c and the actual steam
generation for the month if you are
complying with the emission limits on
a electrical generation (output) basis.
ER31JA13.008</GPH>
section. The first monthly period begins
on the compliance date specified in
§ 63.7495. If the affected source elects to
collect monthly data for up the 11
months preceding the first monthly
period, these additional data points can
be used to compute the 12-month
rolling average in paragraph (f)(3) of this
section.
(1) For each calendar month, you
must use Equation 3a or 3b or 3c of this
section to calculate the average
weighted emission rate for that month.
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
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*
(g) You must develop, and submit
upon request to the applicable
Administrator for review and approval,
an implementation plan for emission
averaging according to the following
procedures and requirements in
paragraphs (g)(1) through (4) of this
section.
*
*
*
*
*
(2) * * *
(i) The identification of all existing
boilers and process heaters in the
averaging group, including for each
either the applicable HAP emission
level or the control technology installed
as of January 31, 2013 and the date on
which you are requesting emission
averaging to commence;
*
*
*
*
*
(iv) The test plan for the measurement
of PM (or TSM), HCl, or mercury
emissions in accordance with the
requirements in § 63.7520;
*
*
*
*
*
(vi) * * *
(B) A description of the methods and
procedures that will be used to
demonstrate that the parameter
indicates proper operation of the control
device; the frequency and content of
monitoring, reporting, and
recordkeeping requirements; and a
demonstration, to the satisfaction of the
Administrator, that the proposed
monitoring frequency is sufficient to
represent control device operating
conditions; and
*
*
*
*
*
(3) The Administrator shall review
and approve or disapprove the plan
according to the following criteria:
*
*
*
*
*
(4) The applicable Administrator shall
not approve an emission averaging
implementation plan containing any of
the following provisions:
*
*
*
*
*
(ii) The inclusion of any emission
source other than an existing unit in the
same subcategories.
*
*
*
*
*
(h) For a group of two or more
existing affected units, each of which
vents through a single common stack,
you may average PM (or TSM), HCl, or
mercury emissions to demonstrate
compliance with the limits for that
pollutant in Table 2 to this subpart if
you satisfy the requirements in
paragraph (i) or (j) of this section.
(i) For a group of two or more existing
units in the same subcategories, each of
which vents through a common
emissions control system to a common
stack, that does not receive emissions
from units in other subcategories or
categories, you may treat such averaging
group as a single existing unit for
purposes of this subpart and comply
with the requirements of this subpart as
if the group were a single unit.
(j) * * *
(1) Conduct performance tests
according to procedures specified in
§ 63.7520 in the common stack if
affected units from other subcategories
vent to the common stack. The emission
limits that the group must comply with
are determined by the use of Equation
6 of this section.
g. Revising paragraph (f)(2).
h. Revising paragraph (j).
■ i. Revising paragraph (k).
■ j. Adding paragraph (l).
■ k. Adding paragraph (m).
The revisions and additions read as
follows:
(2) To demonstrate compliance with
the applicable alternative CO CEMS
emission standard listed in Tables 1, 2,
or 11 through 13 to this subpart, you
must install, certify, operate, and
maintain a CO CEMS and an oxygen
analyzer according to the applicable
procedures under Performance
Specification 4, 4A, or 4B at 40 CFR part
60, appendix B, the site-specific
monitoring plan developed according to
§ 63.7505(d), and the requirements in
§ 63.7540(a)(8) and paragraph (a) of this
section. Any boiler or process heater
that has a CO CEMS that is compliant
with Performance Specification 4, 4A,
or 4B at 40 CFR part 60, appendix B, a
site-specific monitoring plan developed
according to § 63.7505(d), and the
requirements in § 63.7540(a)(8) and
paragraph (a) of this section must use
the CO CEMS to comply with the
applicable alternative CO CEMS
emission standard listed in Tables 1, 2,
or 11 through 13 to this subpart.
(i) You must conduct a performance
evaluation of each CO CEMS according
to the requirements in § 63.8(e) and
■
*
tkelley on DSK3SPTVN1PROD with
Where:
En = HAP emission limit, pounds per million
British thermal units (lb/MMBtu), parts
per million (ppm), or nanograms per dry
standard cubic meter (ng/dscm).
ELi = Appropriate emission limit from Table
2 to this subpart for unit i, in units of lb/
MMBtu, ppm or ng/dscm.
Hi = Heat input from unit i, MMBtu.
§ 63.7525 What are my monitoring,
installation, operation, and maintenance
requirements?
*
*
*
*
(k) The common stack of a group of
two or more existing boilers or process
heaters in the same subcategories
subject to paragraph (h) of this section
may be treated as a separate stack for
purposes of paragraph (b) of this section
and included in an emissions averaging
group subject to paragraph (b) of this
section.
■ 17. Section 63.7525 is amended by:
■ a. Revising paragraph (a)
■ b. Revising paragraph (b).
■ c. Revising paragraph (c) introductory
text.
■ d. Revising paragraphs (d)
introductory text and paragraphs (d)(1)
through (d)(4).
■ e. Revising paragraph (e)(2).
■ f. Revising paragraph (e)(3).
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■
(a) If your boiler or process heater is
subject to a CO emission limit in Tables
1, 2, or 11 through 13 to this subpart,
you must install, operate, and maintain
an oxygen analyzer system, as defined
in § 63.7575, or install, certify, operate
and maintain continuous emission
monitoring systems for CO and oxygen
according to the procedures in
paragraphs (a)(1) through (7) of this
section.
(1) Install the CO CEMS and oxygen
analyzer by the compliance date
specified in § 63.7495. The CO and
oxygen levels shall be monitored at the
same location at the outlet of the boiler
or process heater.
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31JAR3
ER31JA13.012</GPH>
Btu of heat input for that calendar
month.
Er = Emission rate (as determined during the
most recent compliance demonstration
of PM (or TSM), HCl, or mercury from
unit, i, in units of pounds per million
Btu of heat input. Determine the
emission rate for PM (or TSM), HCl, or
mercury by performance testing
according to Table 5 to this subpart, or
by fuel analysis for HCl or mercury or
TSM according to Table 6 to this subpart.
Sa = Actual steam generation for that
calendar month by boiler, i, in units of
pounds.
Cfi = Conversion factor, as calculated during
the most recent compliance test, in units
of million Btu of heat input per pounds
of steam generated for boiler, i.
1.1 = Required discount factor.
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Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
according to Performance Specification
4, 4A, or 4B at 40 CFR part 60, appendix
B.
(ii) During each relative accuracy test
run of the CO CEMS, you must be
collect emission data for CO
concurrently (or within a 30- to 60minute period) by both the CO CEMS
and by Method 10, 10A, or 10B at 40
CFR part 60, appendix A–4. The relative
accuracy testing must be at
representative operating conditions.
(iii) You must follow the quality
assurance procedures (e.g., quarterly
accuracy determinations and daily
calibration drift tests) of Procedure 1 of
appendix F to part 60. The measurement
span value of the CO CEMS must be two
times the applicable CO emission limit,
expressed as a concentration.
(iv) Any CO CEMS that does not
comply with § 63.7525(a) cannot be
used to meet any requirement in this
subpart to demonstrate compliance with
a CO emission limit listed in Tables 1,
2, or 11 through 13 to this subpart.
(v) For a new unit, complete the
initial performance evaluation no later
than July 30, 2013, or 180 days after the
date of initial startup, whichever is
later. For an existing unit, complete the
initial performance evaluation no later
than July 29, 2016.
(3) Complete a minimum of one cycle
of CO and oxygen CEMS operation
(sampling, analyzing, and data
recording) for each successive 15minute period. Collect CO and oxygen
data concurrently. Collect at least four
CO and oxygen CEMS data values
representing the four 15-minute periods
in an hour, or at least two 15-minute
data values during an hour when CEMS
calibration, quality assurance, or
maintenance activities are being
performed.
(4) Reduce the CO CEMS data as
specified in § 63.8(g)(2).
(5) Calculate one-hour arithmetic
averages, corrected to 3 percent oxygen
from each hour of CO CEMS data in
parts per million CO concentration. The
one-hour arithmetic averages required
shall be used to calculate the 30-day or
10-day rolling average emissions. Use
Equation 19–19 in section 12.4.1 of
Method 19 of 40 CFR part 60, appendix
A–7 for calculating the average CO
concentration from the hourly values.
(6) For purposes of collecting CO data,
operate the CO CEMS as specified in
§ 63.7535(b). You must use all the data
collected during all periods in
calculating data averages and assessing
compliance, except that you must
exclude certain data as specified in
§ 63.7535(c). Periods when CO data are
unavailable may constitute monitoring
deviations as specified in § 63.7535(d).
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(7) Operate an oxygen trim system
with the oxygen level set no lower than
the lowest hourly average oxygen
concentration measured during the most
recent CO performance test as the
operating limit for oxygen according to
Table 7 to this subpart.
(b) If your boiler or process heater is
in the unit designed to burn coal/solid
fossil fuel subcategory or the unit
designed to burn heavy liquid
subcategory and has an average annual
heat input rate greater than 250 MMBtu
per hour from solid fossil fuel and/or
heavy liquid, and you demonstrate
compliance with the PM limit instead of
the alternative TSM limit, you must
install, certify, maintain, and operate a
PM CPMS monitoring emissions
discharged to the atmosphere and
record the output of the system as
specified in paragraphs (b)(1) through
(4) of this section. As an alternative to
use of a PM CPMS to demonstrate
compliance with the PM limit, you may
choose to use a PM CEMS. If you choose
to use a PM CEMS to demonstrate
compliance with the PM limit instead of
the alternative TSM limit, you must
install, certify, maintain, and operate a
PM CEMS monitoring emissions
discharged to the atmosphere and
record the output of the system as
specified in paragraph (b)(5) through (8)
of this section. For other boilers or
process heaters, you may elect to use a
PM CPMS or PM CEMS operated in
accordance with this section in lieu of
using other CMS for monitoring PM
compliance (e.g., bag leak detectors, ESP
secondary power, PM scrubber
pressure). Owners of boilers and process
heaters who elect to comply with the
alternative TSM limit are not required to
install a PM CPMS.
(1) Install, certify, operate, and
maintain your PM CPMS according to
the procedures in your approved sitespecific monitoring plan developed in
accordance with § 63.7505(d), the
requirements in § 63.7540(a)(9), and
paragraphs (b)(1)(i) through (iii) of this
section.
(i) The operating principle of the PM
CPMS must be based on in-stack or
extractive light scatter, light
scintillation, beta attenuation, or mass
accumulation detection of PM in the
exhaust gas or representative exhaust
gas sample. The reportable
measurement output from the PM CPMS
must be expressed as milliamps.
(ii) The PM CPMS must have a cycle
time (i.e., period required to complete
sampling, measurement, and reporting
for each measurement) no longer than
60 minutes.
(iii) The PM CPMS must be capable of
detecting and responding to PM
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concentrations of no greater than 0.5
milligram per actual cubic meter.
(2) For a new unit, complete the
initial performance evaluation no later
than July 30, 2013, or 180 days after the
date of initial startup, whichever is
later. For an existing unit, complete the
initial performance evaluation no later
than July 29, 2016.
(3) Collect PM CPMS hourly average
output data for all boiler or process
heater operating hours except as
indicated in § 63.7535(a) through (d).
Express the PM CPMS output as
milliamps.
(4) Calculate the arithmetic 30-day
rolling average of all of the hourly
average PM CPMS output data collected
during all boiler or process heater
operating hours (milliamps).
(5) Install, certify, operate, and
maintain your PM CEMS according to
the procedures in your approved sitespecific monitoring plan developed in
accordance with § 63.7505(d), the
requirements in § 63.7540(a)(9), and
paragraphs (b)(5)(i) through (iv) of this
section.
(i) You shall conduct a performance
evaluation of the PM CEMS according to
the applicable requirements of § 60.8(e),
and Performance Specification 11 at 40
CFR part 60, appendix B of this chapter.
(ii) During each PM correlation testing
run of the CEMS required by
Performance Specification 11 at 40 CFR
part 60, appendix B of this chapter, you
shall collect PM and oxygen (or carbon
dioxide) data concurrently (or within a
30-to 60-minute period) by both the
CEMS and conducting performance tests
using Method 5 at 40 CFR part 60,
appendix A–3 or Method 17 at 40 CFR
part 60, appendix A–6 of this chapter.
(iii) You shall perform quarterly
accuracy determinations and daily
calibration drift tests in accordance with
Procedure 2 at 40 CFR part 60, appendix
F of this chapter. You must perform
Relative Response Audits annually and
perform Response Correlation Audits
every 3 years.
(iv) Within 60 days after the date of
completing each CEMS relative
accuracy test audit or performance test
conducted to demonstrate compliance
with this subpart, you must submit the
relative accuracy test audit data and
performance test data to the EPA by
successfully submitting the data
electronically into the EPA’s Central
Data Exchange by using the Electronic
Reporting Tool (see https://www.epa.gov/
ttn/chief/ert/erttool.html/).
(6) For a new unit, complete the
initial performance evaluation no later
than July 30, 2013, or 180 days after the
date of initial startup, whichever is
later. For an existing unit, complete the
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initial performance evaluation no later
than July 29, 2016.
(7) Collect PM CEMS hourly average
output data for all boiler or process
heater operating hours except as
indicated in § 63.7535(a) through (d).
(8) Calculate the arithmetic 30-day
rolling average of all of the hourly
average PM CEMS output data collected
during all boiler or process heater
operating hours.
(c) If you have an applicable opacity
operating limit in this rule, and are not
otherwise required or elect to install and
operate a PM CPMS, PM CEMS, or a bag
leak detection system, you must install,
operate, certify and maintain each
COMS according to the procedures in
paragraphs (c)(1) through (7) of this
section by the compliance date specified
in § 63.7495.
*
*
*
*
*
(d) If you have an operating limit that
requires the use of a CMS other than a
PM CPMS or COMS, you must install,
operate, and maintain each CMS
according to the procedures in
paragraphs (d)(1) through (5) of this
section by the compliance date specified
in § 63.7495.
(1) The CPMS must complete a
minimum of one cycle of operation
every 15-minutes. You must have a
minimum of four successive cycles of
operation, one representing each of the
four 15-minute periods in an hour, to
have a valid hour of data.
(2) You must operate the monitoring
system as specified in § 63.7535(b), and
comply with the data calculation
requirements specified in § 63.7535(c).
(3) Any 15-minute period for which
the monitoring system is out-of-control
and data are not available for a required
calculation constitutes a deviation from
the monitoring requirements. Other
situations that constitute a monitoring
deviation are specified in § 63.7535(d).
(4) You must determine the 30-day
rolling average of all recorded readings,
except as provided in § 63.7535(c).
*
*
*
*
*
(e) * * *
(2) You must use a flow sensor with
a measurement sensitivity of no greater
than 2 percent of the design flow rate.
(3) You must minimize, consistent
with good engineering practices, the
effects of swirling flow or abnormal
velocity distributions due to upstream
and downstream disturbances.
*
*
*
*
*
(f) * * *
(2) Minimize or eliminate pulsating
pressure, vibration, and internal and
external corrosion consistent with good
engineering practices.
*
*
*
*
*
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(j) If you are not required to use a PM
CPMS and elect to use a fabric filter bag
leak detection system to comply with
the requirements of this subpart, you
must install, calibrate, maintain, and
continuously operate the bag leak
detection system as specified in
paragraphs (j)(1) through (6) of this
section.
(1) You must install a bag leak
detection sensor(s) in a position(s) that
will be representative of the relative or
absolute PM loadings for each exhaust
stack, roof vent, or compartment (e.g.,
for a positive pressure fabric filter) of
the fabric filter.
(2) Conduct a performance evaluation
of the bag leak detection system in
accordance with your monitoring plan
and consistent with the guidance
provided in EPA–454/R–98–015
(incorporated by reference, see § 63.14).
(3) Use a bag leak detection system
certified by the manufacturer to be
capable of detecting PM emissions at
concentrations of 10 milligrams per
actual cubic meter or less.
(4) Use a bag leak detection system
equipped with a device to record
continuously the output signal from the
sensor.
(5) Use a bag leak detection system
equipped with a system that will alert
plant operating personnel when an
increase in relative PM emissions over
a preset level is detected. The alert must
easily recognizable (e.g., heard or seen)
by plant operating personnel.
(6) Where multiple bag leak detectors
are required, the system’s
instrumentation and alert may be shared
among detectors.
(k) For each unit that meets the
definition of limited-use boiler or
process heater, you must keep fuel use
records for the days the boiler or process
heater was operating.
(l) For each unit for which you decide
to demonstrate compliance with the
mercury or HCl emissions limits in
Tables 1 or 2 or 11 through 13 of this
subpart by use of a CEMS for mercury
or HCl, you must install, certify,
maintain, and operate a CEMS
measuring emissions discharged to the
atmosphere and record the output of the
system as specified in paragraphs (l)(1)
through (8) of this section. For HCl, this
option for an affected unit takes effect
on the date a final performance
specification for a HCl CEMS is
published in the Federal Register or the
date of approval of a site-specific
monitoring plan.
(1) Notify the Administrator one
month before starting use of the CEMS,
and notify the Administrator one month
before stopping use of the CEMS.
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(2) Each CEMS shall be installed,
certified, operated, and maintained
according to the requirements in
§ 63.7540(a)(14) for a mercury CEMS
and § 63.7540(a)(15) for a HCl CEMS.
(3) For a new unit, you must complete
the initial performance evaluation of the
CEMS by the latest of the dates specified
in paragraph (l)(3)(i) through (iii) of this
section.
(i) No later than July 30, 2013.
(ii) No later 180 days after the date of
initial startup.
(iii) No later 180 days after notifying
the Administrator before starting to use
the CEMS in place of performance
testing or fuel analysis to demonstrate
compliance.
(4) For an existing unit, you must
complete the initial performance
evaluation by the latter of the two dates
specified in paragraph (l)(4)(i) and (ii) of
this section.
(i) No later than July 29, 2016.
(ii) No later 180 days after notifying
the Administrator before starting to use
the CEMS in place of performance
testing or fuel analysis to demonstrate
compliance.
(5) Compliance with the applicable
emissions limit shall be determined
based on the 30-day rolling average of
the hourly arithmetic average emissions
rates using the continuous monitoring
system outlet data. The 30-day rolling
arithmetic average emission rate (lb/
MMBtu) shall be calculated using the
equations in EPA Reference Method 19
at 40 CFR part 60, appendix A–7, but
substituting the mercury or HCl
concentration for the pollutant
concentrations normally used in
Method 19.
(6) Collect CEMS hourly averages for
all operating hours on a 30-day rolling
average basis. Collect at least four CMS
data values representing the four 15minute periods in an hour, or at least
two 15-minute data values during an
hour when CMS calibration, quality
assurance, or maintenance activities are
being performed.
(7) The one-hour arithmetic averages
required shall be expressed in lb/
MMBtu and shall be used to calculate
the boiler 30-day and 10-day rolling
average emissions.
(8) You are allowed to substitute the
use of the PM, mercury or HCl CEMS for
the applicable fuel analysis, annual
performance test, and operating limits
specified in Table 4 to this subpart to
demonstrate compliance with the PM,
mercury or HCl emissions limit, and if
you are using an acid gas wet scrubber
or dry sorbent injection control
technology to comply with the HCl
emission limit, you are allowed to
substitute the use of a sulfur dioxide
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(SO2) CEMS for the applicable fuel
analysis, annual performance test, and
operating limits specified in Table 4 to
this subpart to demonstrate compliance
with HCl emissions limit.
(m) If your unit is subject to a HCl
emission limit in Tables 1, 2, or 11
through 13 of this subpart and you have
an acid gas wet scrubber or dry sorbent
injection control technology and you
use an SO2 CEMS, you must install the
monitor at the outlet of the boiler or
process heater, downstream of all
emission control devices, and you must
install, certify, operate, and maintain
the CEMS according to part 75 of this
chapter.
(1) The SO2 CEMS must be installed
by the compliance date specified in
§ 63.7495.
(2) For on-going quality assurance
(QA), the SO2 CEMS must meet the
applicable daily, quarterly, and
semiannual or annual requirements in
sections 2.1 through 2.3 of appendix B
to part 75 of this chapter, with the
following addition: You must perform
the linearity checks required in section
2.2 of appendix B to part 75 of this
chapter if the SO2 CEMS has a span
value of 30 ppm or less.
(3) For a new unit, the initial
performance evaluation shall be
completed no later than July 30, 2013,
or 180 days after the date of initial
startup, whichever is later. For an
existing unit, the initial performance
evaluation shall be completed no later
than July 29, 2016.
(4) For purposes of collecting SO2
data, you must operate the SO2 CEMS as
specified in § 63.7535(b). You must use
all the data collected during all periods
in calculating data averages and
assessing compliance, except that you
must exclude certain data as specified
in § 63.7535(c). Periods when SO2 data
are unavailable may constitute
monitoring deviations as specified in
§ 63.7535(d).
(5) Collect CEMS hourly averages for
all operating hours on a 30-day rolling
average basis.
(6) Use only unadjusted, qualityassured SO2 concentration values in the
emissions calculations; do not apply
bias adjustment factors to the part 75
SO2 data and do not use part 75
substitute data values.
■ 18. Section 63.7530 is amended by:
■ a. Revising paragraph (a).
■ b. Revising paragraph (b) introductory
text.
■ c. Redesignating paragraph (b)(3) as
paragraph (b)(4) and adding new
paragraph (b)(3).
■ d. Revising newly designated
paragraph (b)(4).
■ e. Revising paragraph (c), (c)(2)
through (4).
■ f. Adding paragraph (c)(5).
■ g. Revising paragraphs (d), (e), (g), and
(h).
■ h. Adding paragraph (i).
The revisions and additions read as
follows:
Where:
TSMinput = Maximum amount of TSM
entering the boiler or process heater
through fuels burned in units of pounds
per million Btu.
TSMi = Arithmetic average concentration of
TSM in fuel type, i, analyzed according
to § 63.7521, in units of pounds per
million Btu.
Qi = Fraction of total heat input from fuel
type, i, based on the fuel mixture that
has the highest content of TSM. If you
do not burn multiple fuel types during
the performance testing, it is not
necessary to determine the value of this
term. Insert a value of ‘‘1’’ for Qi.
n = Number of different fuel types burned in
your boiler or process heater for the
mixture that has the highest content of
TSM.
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§ 63.7530 How do I demonstrate initial
compliance with the emission limitations,
fuel specifications and work practice
standards?
(a) You must demonstrate initial
compliance with each emission limit
that applies to you by conducting initial
performance tests and fuel analyses and
establishing operating limits, as
applicable, according to § 63.7520,
paragraphs (b) and (c) of this section,
and Tables 5 and 7 to this subpart. The
requirement to conduct a fuel analysis
is not applicable for units that burn a
single type of fuel, as specified by
§ 63.7510(a)(2)(i). If applicable, you
must also install, operate, and maintain
all applicable CMS (including CEMS,
COMS, and CPMS) according to
§ 63.7525.
(4) You must establish parameter
operating limits according to paragraphs
(b)(4)(i) through (ix) of this section. As
indicated in Table 4 to this subpart, you
are not required to establish and comply
with the operating parameter limits
when you are using a CEMS to monitor
and demonstrate compliance with the
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(b) If you demonstrate compliance
through performance testing, you must
establish each site-specific operating
limit in Table 4 to this subpart that
applies to you according to the
requirements in § 63.7520, Table 7 to
this subpart, and paragraph (b)(4) of this
section, as applicable. You must also
conduct fuel analyses according to
§ 63.7521 and establish maximum fuel
pollutant input levels according to
paragraphs (b)(1) through (3) of this
section, as applicable, and as specified
in § 63.7510(a)(2). (Note that
§ 63.7510(a)(2) exempts certain fuels
from the fuel analysis requirements.)
However, if you switch fuel(s) and
cannot show that the new fuel(s) does
(do) not increase the chlorine, mercury,
or TSM input into the unit through the
results of fuel analysis, then you must
repeat the performance test to
demonstrate compliance while burning
the new fuel(s).
*
*
*
*
*
(3) If you opt to comply with the
alternative TSM limit, you must
establish the maximum TSM fuel input
(TSMinput) for solid or liquid fuels
during the initial fuel analysis according
to the procedures in paragraphs (b)(3)(i)
through (iii) of this section.
(i) You must determine the fuel type
or fuel mixture that you could burn in
your boiler or process heater that has
the highest content of TSM.
(ii) During the fuel analysis for TSM,
you must determine the fraction of the
total heat input for each fuel type
burned (Qi) based on the fuel mixture
that has the highest content of TSM, and
the average TSM concentration of each
fuel type burned (TSMi).
(iii) You must establish a maximum
TSM input level using Equation 9 of this
section.
applicable emission limit for that
control device parameter.
(i) For a wet acid gas scrubber, you
must establish the minimum scrubber
effluent pH and liquid flow rate as
defined in § 63.7575, as your operating
limits during the performance test
during which you demonstrate
compliance with your applicable limit.
If you use a wet scrubber and you
conduct separate performance tests for
HCl and mercury emissions, you must
establish one set of minimum scrubber
effluent pH, liquid flow rate, and
E:\FR\FM\31JAR3.SGM
31JAR3
ER31JA13.013</GPH>
7174
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
7175
Where:
X1 = the PM CPMS data points for the three
runs constituting the performance test,
Y1 = the PM concentration value for the three
runs constituting the performance test,
and
n = the number of data points.
X1 = the three run average milliamp output
from you PM CPMS, and
z = the milliamp equivalent of your
instrument zero determined from (B)(i).
(C) If the average of your three PM
compliance test runs is at or above 75
percent of your PM emission limit you
must determine your 30-day rolling
average operating limit by averaging the
PM CPMS milliamp output
corresponding to your three PM
performance test runs that demonstrate
compliance with the emission limit
using equation 13 and you must submit
all compliance test and PM CPMS data
according to the reporting requirements
in paragraph (b)(4)(ii)(F) of this section.
tkelley on DSK3SPTVN1PROD with
(3) With your instrument zero
expressed in milliamps, your three run
average PM CPMS milliamp value, and
your three run average PM
concentration from your three
compliance tests, determine a
relationship of lb/MMBtu per milliamp
with equation 11.
Where:
R = the relative lb/MMBtu per milliamp for
your PM CPMS,
Y1 = the three run average lb/MMBtu PM
concentration,
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(4) Determine your source specific 30day rolling average operating limit using
the lb/MMBtu per milliamp value from
Equation 11 in equation 12, below. This
sets your operating limit at the PM
CPMS output value corresponding to 75
percent of your emission limit.
Where:
Ol = the operating limit for your PM CPMS
on a 30-day rolling average, in
milliamps.
L = your source emission limit expressed in
lb/MMBtu,
z = your instrument zero in milliamps,
determined from (B)(i), and
R = the relative lb/MMBtu per milliamp for
your PM CPMS, from Equation 11.
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Where:
X1 = the PM CPMS data points for all runs
i,
n = the number of data points, and
Oh = your site specific operating limit, in
milliamps.
(D) To determine continuous
compliance, you must record the PM
E:\FR\FM\31JAR3.SGM
31JAR3
ER31JA13.017</GPH>
paragraphs (b)(4)(ii)(B)(1) through (4) of
this section.
(1) Determine your instrument zero
output with one of the following
procedures:
(i) Zero point data for in-situ
instruments should be obtained by
removing the instrument from the stack
and monitoring ambient air on a test
bench.
(ii) Zero point data for extractive
instruments should be obtained by
removing the extractive probe from the
stack and drawing in clean ambient air.
(iii) The zero point may also be
established by performing manual
reference method measurements when
the flue gas is free of PM emissions or
contains very low PM concentrations
(e.g., when your process is not
operating, but the fans are operating or
your source is combusting only natural
gas) and plotting these with the
compliance data to find the zero
intercept.
(iv) If none of the steps in paragraphs
(b)(4)(ii)(B)(1)(i) through (iii) of this
section are possible, you must use a zero
output value provided by the
manufacturer.
(2) Determine your PM CPMS
instrument average in milliamps, and
the average of your corresponding three
PM compliance test runs, using
equation 10.
ER31JA13.015</GPH> ER31JA13.016</GPH>
establishment of its relationship to
manual reference method measurements
must be determined in units of
milliamps.
(2) Your PM CPMS operating range
must be capable of reading PM
concentrations from zero to a level
equivalent to at least two times your
allowable emission limit. If your PM
CPMS is an auto-ranging instrument
capable of multiple scales, the primary
range of the instrument must be capable
of reading PM concentration from zero
to a level equivalent to two times your
allowable emission limit.
(3) During the initial performance test
or any such subsequent performance
test that demonstrates compliance with
the PM limit, record and average all
milliamp output values from the PM
CPMS for the periods corresponding to
the compliance test runs (e.g., average
all your PM CPMS output values for
three corresponding 2-hour Method 5I
test runs).
(B) If the average of your three PM
performance test runs are below 75
percent of your PM emission limit, you
must calculate an operating limit by
establishing a relationship of PM CPMS
signal to PM concentration using the PM
CPMS instrument zero, the average PM
CPMS values corresponding to the three
compliance test runs, and the average
PM concentration from the Method 5 or
performance test with the procedures in
ER31JA13.014</GPH>
pressure drop operating limits. The
minimum scrubber effluent pH
operating limit must be established
during the HCl performance test. If you
conduct multiple performance tests, you
must set the minimum liquid flow rate
operating limit at the higher of the
minimum values established during the
performance tests.
(ii) For any particulate control device
(e.g., ESP, particulate wet scrubber,
fabric filter) for which you use a PM
CPMS, you must establish your PM
CPMS operating limit and determine
compliance with it according to
paragraphs (b)(4)(ii)(A) through (F) of
this section.
(A) Determine your operating limit as
the average PM CPMS output value
recorded during the most recent
performance test run demonstrating
compliance with the filterable PM
emission limit or at the PM CPMS
output value corresponding to 75
percent of the emission limit if your PM
performance test demonstrates
compliance below 75 percent of the
emission limit. You must verify an
existing or establish a new operating
limit after each repeated performance
test. You must repeat the performance
test annually and reassess and adjust the
site-specific operating limit in
accordance with the results of the
performance test.
(1) Your PM CPMS must provide a 4–
20 milliamp output and the
7176
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
(E) Use EPA Method 5 of appendix A
to part 60 of this chapter to determine
PM emissions. For each performance
test, conduct three separate runs under
the conditions that exist when the
affected source is operating at the
highest load or capacity level reasonably
expected to occur. Conduct each test
run to collect a minimum sample
volume specified in Tables 1, 2, or 11
through 13 to this subpart, as
applicable, for determining compliance
with a new source limit or an existing
source limit. Calculate the average of the
results from three runs to determine
compliance. You need not determine
the PM collected in the impingers
(‘‘back half’’) of the Method 5
particulate sampling train to
demonstrate compliance with the PM
standards of this subpart. This shall not
preclude the permitting authority from
requiring a determination of the ‘‘back
half’’ for other purposes.
(F) For PM performance test reports
used to set a PM CPMS operating limit,
the electronic submission of the test
report must also include the make and
model of the PM CPMS instrument,
serial number of the instrument,
analytical principle of the instrument
(e.g. beta attenuation), span of the
instruments primary analytical range,
milliamp value equivalent to the
instrument zero output, technique by
which this zero value was determined,
and the average milliamp signals
corresponding to each PM compliance
test run. (iii) For a particulate wet
scrubber, you must establish the
minimum pressure drop and liquid flow
rate as defined in § 63.7575, as your
operating limits during the three-run
performance test during which you
demonstrate compliance with your
applicable limit. If you use a wet
scrubber and you conduct separate
performance tests for PM and TSM
emissions, you must establish one set of
minimum scrubber liquid flow rate and
pressure drop operating limits. The
minimum scrubber effluent pH
operating limit must be established
during the HCl performance test. If you
conduct multiple performance tests, you
must set the minimum liquid flow rate
and pressure drop operating limits at
the higher of the minimum values
established during the performance
tests.
(iii) For an electrostatic precipitator
(ESP) operated with a wet scrubber, you
must establish the minimum total
secondary electric power input, as
defined in § 63.7575, as your operating
limit during the three-run performance
test during which you demonstrate
compliance with your applicable limit.
(These operating limits do not apply to
ESP that are operated as dry controls
without a wet scrubber.)
(iv) For a dry scrubber, you must
establish the minimum sorbent injection
rate for each sorbent, as defined in
§ 63.7575, as your operating limit during
the three-run performance test during
which you demonstrate compliance
with your applicable limit.
(v) For activated carbon injection, you
must establish the minimum activated
carbon injection rate, as defined in
§ 63.7575, as your operating limit during
the three-run performance test during
which you demonstrate compliance
with your applicable limit.
(vi) The operating limit for boilers or
process heaters with fabric filters that
demonstrate continuous compliance
through bag leak detection systems is
that a bag leak detection system be
installed according to the requirements
in § 63.7525, and that each fabric filter
must be operated such that the bag leak
detection system alert is not activated
more than 5 percent of the operating
time during a 6-month period.
(vii) For a minimum oxygen level, if
you conduct multiple performance tests,
you must set the minimum oxygen level
at the lower of the minimum values
established during the performance
tests.
(viii) The operating limit for boilers or
process heaters that demonstrate
continuous compliance with the HCl
emission limit using a SO2 CEMS is to
install and operate the SO2 according to
the requirements in § 63.7525(m)
establish a maximum SO2 emission rate
equal to the highest hourly average SO2
measurement during the most recent
three-run performance test for HCl.
(c) If you elect to demonstrate
compliance with an applicable emission
limit through fuel analysis, you must
conduct fuel analyses according to
§ 63.7521 and follow the procedures in
paragraphs (c)(1) through (5) of this
section.
*
*
*
*
*
(2) You must determine the 90th
percentile confidence level fuel
pollutant concentration of the
composite samples analyzed for each
fuel type using the one-sided t-statistic
test described in Equation 15 of this
section.
Where:
P90 = 90th percentile confidence level
pollutant concentration, in pounds per
million Btu.
Mean = Arithmetic average of the fuel
pollutant concentration in the fuel
samples analyzed according to § 63.7521,
in units of pounds per million Btu.
SD = Standard deviation of the mean of
pollutant concentration in the fuel
samples analyzed according to § 63.7521,
in units of pounds per million Btu. SD
is calculated as the sample standard
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E:\FR\FM\31JAR3.SGM
31JAR3
ER31JA13.019</GPH>
basis, updated at the end of each new
operating hour. Use Equation 14 to
determine the 30-day rolling average.
ER31JA13.018</GPH>
data collected by the PM CPMS for all
operating hours to calculate the
arithmetic average operating parameter
in units of the operating limit
(milliamps) on a 30-day rolling average
Where:
30-day = 30-day average.
Hpvi = is the hourly parameter value for hour
i
n = is the number of valid hourly parameter
values collected over the previous 720
operating hours.
tkelley on DSK3SPTVN1PROD with
CPMS output data for all periods when
the process is operating and the PM
CPMS is not out-of-control. You must
demonstrate continuous compliance by
using all quality-assured hourly average
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
(3) To demonstrate compliance with
the applicable emission limit for HCl,
Where:
HCl = HCl emission rate from the boiler or
process heater in units of pounds per
million Btu.
Ci90 = 90th percentile confidence level
concentration of chlorine in fuel type, i,
in units of pounds per million Btu as
calculated according to Equation 11 of
this section.
Qi = Fraction of total heat input from fuel
type, i, based on the fuel mixture that
has the highest content of chlorine. If
you do not burn multiple fuel types, it
is not necessary to determine the value
of this term. Insert a value of ‘‘1’’ for Qi.
n = Number of different fuel types burned in
your boiler or process heater for the
mixture that has the highest content of
chlorine.
1.028 = Molecular weight ratio of HCl to
chlorine.
Where:
Mercury = Mercury emission rate from the
boiler or process heater in units of
pounds per million Btu.
Hgi90 = 90th percentile confidence level
concentration of mercury in fuel, i, in
units of pounds per million Btu as
calculated according to Equation 11 of
this section.
Qi = Fraction of total heat input from fuel
type, i, based on the fuel mixture that
has the highest mercury content. If you
do not burn multiple fuel types, it is not
necessary to determine the value of this
term. Insert a value of ‘‘1’’ for Qi.
n = Number of different fuel types burned in
your boiler or process heater for the
mixture that has the highest mercury
content.
(5) To demonstrate compliance with
the applicable emission limit for TSM
for solid or liquid fuels, the TSM
emission rate that you calculate for your
boiler or process heater from solid fuels
using Equation 18 of this section must
not exceed the applicable emission limit
for TSM.
Where:
Metals = TSM emission rate from the boiler
or process heater in units of pounds per
million Btu.
TSMi90 = 90th percentile confidence level
concentration of TSM in fuel, i, in units
of pounds per million Btu as calculated
according to Equation 11 of this section.
Qi = Fraction of total heat input from fuel
type, i, based on the fuel mixture that
has the highest TSM content. If you do
not burn multiple fuel types, it is not
necessary to determine the value of this
term. Insert a value of ‘‘1’’ for Qi.
n = Number of different fuel types burned in
your boiler or process heater for the
mixture that has the highest TSM
content.
that you conducted a tune-up of the
unit.
(e) You must include with the
Notification of Compliance Status a
signed certification that the energy
assessment was completed according to
Table 3 to this subpart and is an
accurate depiction of your facility at the
time of the assessment.
*
*
*
*
*
(g) If you elect to demonstrate that a
gaseous fuel meets the specifications of
another gas 1 fuel as defined in
§ 63.7575, you must conduct an initial
fuel specification analyses according to
§ 63.7521(f) through (i) and according to
the frequency listed in § 63.7540(c) and
maintain records of the results of the
testing as outlined in § 63.7555(g). For
samples where the initial mercury
specification has not been exceeded,
you will include a signed certification
with the Notification of Compliance
Status that the initial fuel specification
test meets the gas specification outlined
in the definition of other gas 1 fuels.
(h) If you own or operate a unit
subject to emission limits in Tables 1 or
2 or 11 through 13 to this subpart, you
must meet the work practice standard
according to Table 3 of this subpart.
During startup and shutdown, you must
only follow the work practice standards
according to item 5 of Table 3 of this
subpart.
(i) If you opt to comply with the
alternative SO2 CEMS operating limit in
Tables 4 and 8 to this subpart, you may
do so only if your affected boiler or
process heater:
(1) Has a system using wet scrubber
or dry sorbent injection and SO2 CEMS
installed on the unit; and
(2) At all times, you operate the wet
scrubber or dry sorbent injection for
acid gas control on the unit consistent
with § 63.7500(a)(3); and
(3) You establish a unit-specific
maximum SO2 operating limit by
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the HCl emission rate that you calculate
for your boiler or process heater using
Equation 16 of this section must not
exceed the applicable emission limit for
HCl.
E:\FR\FM\31JAR3.SGM
31JAR3
ER31JA13.021</GPH> ER31JA13.022</GPH>
(4) To demonstrate compliance with
the applicable emission limit for
mercury, the mercury emission rate that
you calculate for your boiler or process
heater using Equation 17 of this section
must not exceed the applicable emission
limit for mercury.
ER31JA13.020</GPH>
tkelley on DSK3SPTVN1PROD with
deviation divided by the square root of
the number of samples.
t = t distribution critical value for 90th
percentile (t0.1) probability for the
appropriate degrees of freedom (number
(d) If you own or operate an existing
unit with a heat input capacity of less
than 10 million Btu per hour or a unit
in the unit designed to burn gas 1
subcategory, you must submit a signed
statement in the Notification of
Compliance Status report that indicates
of samples minus one) as obtained from
a t-Distribution Critical Value Table.
7177
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
collecting the minimum hourly SO2
emission rate on the SO2 CEMS during
the paired 3-run test for HCl. The
maximum SO2 operating limit is equal
to the highest hourly average SO2
concentration measured during the most
recent HCl performance test.
■ 19. Section 63.7533 is amended by:
■ a. Revising the section heading.
■ b. Revising paragraph (a).
■ c. Revising paragraphs (b)(1) and (4).
■ d. Revising paragraphs (c)
introductory text, (c)(1)(i) and (ii),
(c)(2)(i), and (c)(3).
■ e. Revising paragraph (d) through (f).
■ f. Adding paragraph (g).
The revisions and addition read as
follows:
§ 63.7533 Can I use efficiency credits
earned from implementation of energy
conservation measures to comply with this
subpart?
(a) If you elect to comply with the
alternative equivalent output-based
emission limits, instead of the heat
input-based limits listed in Table 2 to
this subpart, and you want to take credit
for implementing energy conservation
measures identified in an energy
assessment, you may demonstrate
compliance using efficiency credits
according to the procedures in this
section. You may use this compliance
approach for an existing affected boiler
for demonstrating initial compliance
according to § 63.7522(e) and for
demonstrating monthly compliance
according to § 63.7522(f). Owners or
operators using this compliance
approach must establish an emissions
benchmark, calculate and document the
tkelley on DSK3SPTVN1PROD with
Where:
ECredits = Energy Input Savings for all
energy conservation measures
implemented for an affected boiler,
expressed as a decimal fraction of the
baseline energy input.
EISiactual = Energy Input Savings for each
energy conservation measure, i,
implemented for an affected boiler,
million Btu per year.
EIbaseline = Energy Input baseline for the
affected boiler, million Btu per year.
n = Number of energy conservation measures
included in the efficiency credit for the
affected boiler.
(ii) [Reserved]
(d) The owner or operator shall
develop, and submit for approval upon
request by the Administrator, an
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efficiency credits, develop an
Implementation Plan, comply with the
general reporting requirements, and
apply the efficiency credit according to
the procedures in paragraphs (b)
through (f) of this section. You cannot
use this compliance approach for a new
or reconstructed affected boiler.
Additional guidance from the
Department of Energy on efficiency
credits is available at: https://
www.epa.gov/ttn/atw/boiler/
boilerpg.html.
(b) * * *
(1) The benchmark from which
efficiency credits may be generated shall
be determined by using the most
representative, accurate, and reliable
process available for the source. The
benchmark shall be established for a
one-year period before the date that an
energy demand reduction occurs, unless
it can be demonstrated that a different
time period is more representative of
historical operations.
*
*
*
*
*
(4) Collect non-energy related facility
and operational data to normalize, if
necessary, the benchmark to current
operations, such as building size,
operating hours, etc. If possible, use
actual data that are current and timely
rather than estimated data.
(c) Efficiency credits can be generated
if the energy conservation measures
were implemented after January 1, 2008
and if sufficient information is available
to determine the appropriate value of
credits.
(1) The following emission points
cannot be used to generate efficiency
credits:
(i) Energy conservation measures
implemented on or before January 1,
2008, unless the level of energy demand
reduction is increased after January 1,
2008, in which case credit will be
allowed only for change in demand
reduction achieved after January 1,
2008.
(ii) Efficiency credits on shut-down
boilers. Boilers that are shut down
cannot be used to generate credits
unless the facility provides
documentation linking the permanent
shutdown to energy conservation
measures identified in the energy
assessment. In this case, the bench
established for the affected boiler to
which the credits from the shutdown
will be applied must be revised to
include the benchmark established for
the shutdown boiler.
(2) * * *
(i) Calculate annual credits for all
energy demand points. Use Equation 19
to calculate credits. Energy conservation
measures that meet the criteria of
paragraph (c)(1) of this section shall not
be included, except as specified in
paragraph (c)(1)(i) of this section.
*
*
*
*
*
(3) Credits are generated by the
difference between the benchmark that
is established for each affected boiler,
and the actual energy demand
reductions from energy conservation
measures implemented after January 1,
2008. Credits shall be calculated using
Equation 19 of this section as follows:
(i) The overall equation for calculating
credits is:
Implementation Plan containing all of
the information required in this
paragraph for all boilers to be included
in an efficiency credit approach. The
Implementation Plan shall identify all
existing affected boilers to be included
in applying the efficiency credits. The
Implementation Plan shall include a
description of the energy conservation
measures implemented and the energy
savings generated from each measure
and an explanation of the criteria used
for determining that savings. If
requested, you must submit the
implementation plan for efficiency
credits to the Administrator for review
and approval no later than 180 days
before the date on which the facility
intends to demonstrate compliance
using the efficiency credit approach.
(e) The emissions rate as calculated
using Equation 20 of this section from
each existing boiler participating in the
efficiency credit option must be in
compliance with the limits in Table 2 to
this subpart at all times the affected unit
is operating, following the compliance
date specified in § 63.7495.
(f) You must use Equation 20 of this
section to demonstrate initial
compliance by demonstrating that the
emissions from the affected boiler
participating in the efficiency credit
compliance approach do not exceed the
emission limits in Table 2 to this
subpart.
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E:\FR\FM\31JAR3.SGM
31JAR3
ER31JA13.023</GPH>
7178
Where:
Eadj = Emission level adjusted by applying
the efficiency credits earned, lb per
million Btu steam output (or lb per
MWh) for the affected boiler.
Em = Emissions measured during the
performance test, lb per million Btu
steam output (or lb per MWh) for the
affected boiler.
ECredits = Efficiency credits from Equation
19 for the affected boiler.
(g) As part of each compliance report
submitted as required under § 63.7550,
you must include documentation that
the energy conservation measures
implemented continue to generate the
credit for use in demonstrating
compliance with the emission limits.
■ 20. Section 63.7535 is amended by
revising the section heading and
paragraphs (b), (c), and (d) to read as
follows:
§ 63.7535 Is there a minimum amount of
monitoring data I must obtain?
tkelley on DSK3SPTVN1PROD with
*
*
*
*
*
(b) You must operate the monitoring
system and collect data at all required
intervals at all times that each boiler or
process heater is operating and
compliance is required, except for
periods of monitoring system
malfunctions or out of control periods
(see § 63.8(c)(7) of this part), and
required monitoring system quality
assurance or control activities,
including, as applicable, calibration
checks, required zero and span
adjustments, and scheduled CMS
maintenance as defined in your sitespecific monitoring plan. A monitoring
system malfunction is any sudden,
infrequent, not reasonably preventable
failure of the monitoring system to
provide valid data. Monitoring system
failures that are caused in part by poor
maintenance or careless operation are
not malfunctions. You are required to
complete monitoring system repairs in
response to monitoring system
malfunctions or out-of-control periods
and to return the monitoring system to
operation as expeditiously as
practicable.
(c) You may not use data recorded
during monitoring system malfunctions
or out-of-control periods, repairs
associated with monitoring system
malfunctions or out-of-control periods,
or required monitoring system quality
assurance or control activities in data
averages and calculations used to report
emissions or operating levels. You must
record and make available upon request
results of CMS performance audits and
dates and duration of periods when the
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CMS is out of control to completion of
the corrective actions necessary to
return the CMS to operation consistent
with your site-specific monitoring plan.
You must use all the data collected
during all other periods in assessing
compliance and the operation of the
control device and associated control
system.
(d) Except for periods of monitoring
system malfunctions, repairs associated
with monitoring system malfunctions,
and required monitoring system quality
assurance or quality control activities
(including, as applicable, system
accuracy audits, calibration checks, and
required zero and span adjustments),
failure to collect required data is a
deviation of the monitoring
requirements. In calculating monitoring
results, do not use any data collected
during periods when the monitoring
system is out of control as specified in
your site-specific monitoring plan,
while conducting repairs associated
with periods when the monitoring
system is out of control, or while
conducting required monitoring system
quality assurance or quality control
activities. You must calculate
monitoring results using all other
monitoring data collected while the
process is operating. You must report all
periods when the monitoring system is
out of control in your annual report.
■ 21. Section 63.7540 is revised to read
as follows:
§ 63.7540 How do I demonstrate
continuous compliance with the emission
limitations, fuel specifications and work
practice standards?
(a) You must demonstrate continuous
compliance with each emission limit in
Tables 1 and 2 or 11 through 13 to this
subpart, the work practice standards in
Table 3 to this subpart, and the
operating limits in Table 4 to this
subpart that applies to you according to
the methods specified in Table 8 to this
subpart and paragraphs (a)(1) through
(19) of this section.
(1) Following the date on which the
initial compliance demonstration is
completed or is required to be
completed under §§ 63.7 and 63.7510,
whichever date comes first, operation
above the established maximum or
below the established minimum
operating limits shall constitute a
deviation of established operating limits
listed in Table 4 of this subpart except
during performance tests conducted to
determine compliance with the
emission limits or to establish new
operating limits. Operating limits must
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be confirmed or reestablished during
performance tests.
(2) As specified in § 63.7550(c), you
must keep records of the type and
amount of all fuels burned in each
boiler or process heater during the
reporting period to demonstrate that all
fuel types and mixtures of fuels burned
would result in either of the following:
(i) Lower emissions of HCl, mercury,
and TSM than the applicable emission
limit for each pollutant, if you
demonstrate compliance through fuel
analysis.
(ii) Lower fuel input of chlorine,
mercury, and TSM than the maximum
values calculated during the last
performance test, if you demonstrate
compliance through performance
testing.
(3) If you demonstrate compliance
with an applicable HCl emission limit
through fuel analysis for a solid or
liquid fuel and you plan to burn a new
type of solid or liquid fuel, you must
recalculate the HCl emission rate using
Equation 12 of § 63.7530 according to
paragraphs (a)(3)(i) through (iii) of this
section. You are not required to conduct
fuel analyses for the fuels described in
§ 63.7510(a)(2)(i) through (iii). You may
exclude the fuels described in
§ 63.7510(a)(2)(i) through (iii) when
recalculating the HCl emission rate.
(i) You must determine the chlorine
concentration for any new fuel type in
units of pounds per million Btu, based
on supplier data or your own fuel
analysis, according to the provisions in
your site-specific fuel analysis plan
developed according to § 63.7521(b).
(ii) You must determine the new
mixture of fuels that will have the
highest content of chlorine.
(iii) Recalculate the HCl emission rate
from your boiler or process heater under
these new conditions using Equation 12
of § 63.7530. The recalculated HCl
emission rate must be less than the
applicable emission limit.
(4) If you demonstrate compliance
with an applicable HCl emission limit
through performance testing and you
plan to burn a new type of fuel or a new
mixture of fuels, you must recalculate
the maximum chlorine input using
Equation 7 of § 63.7530. If the results of
recalculating the maximum chlorine
input using Equation 7 of § 63.7530 are
greater than the maximum chlorine
input level established during the
previous performance test, then you
must conduct a new performance test
within 60 days of burning the new fuel
type or fuel mixture according to the
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procedures in § 63.7520 to demonstrate
that the HCl emissions do not exceed
the emission limit. You must also
establish new operating limits based on
this performance test according to the
procedures in § 63.7530(b). In
recalculating the maximum chlorine
input and establishing the new
operating limits, you are not required to
conduct fuel analyses for and include
the fuels described in § 63.7510(a)(2)(i)
through (iii).
(5) If you demonstrate compliance
with an applicable mercury emission
limit through fuel analysis, and you
plan to burn a new type of fuel, you
must recalculate the mercury emission
rate using Equation 13 of § 63.7530
according to the procedures specified in
paragraphs (a)(5)(i) through (iii) of this
section. You are not required to conduct
fuel analyses for the fuels described in
§ 63.7510(a)(2)(i) through (iii). You may
exclude the fuels described in
§ 63.7510(a)(2)(i) through (iii) when
recalculating the mercury emission rate.
(i) You must determine the mercury
concentration for any new fuel type in
units of pounds per million Btu, based
on supplier data or your own fuel
analysis, according to the provisions in
your site-specific fuel analysis plan
developed according to § 63.7521(b).
(ii) You must determine the new
mixture of fuels that will have the
highest content of mercury.
(iii) Recalculate the mercury emission
rate from your boiler or process heater
under these new conditions using
Equation 13 of § 63.7530. The
recalculated mercury emission rate must
be less than the applicable emission
limit.
(6) If you demonstrate compliance
with an applicable mercury emission
limit through performance testing, and
you plan to burn a new type of fuel or
a new mixture of fuels, you must
recalculate the maximum mercury input
using Equation 8 of § 63.7530. If the
results of recalculating the maximum
mercury input using Equation 8 of
§ 63.7530 are higher than the maximum
mercury input level established during
the previous performance test, then you
must conduct a new performance test
within 60 days of burning the new fuel
type or fuel mixture according to the
procedures in § 63.7520 to demonstrate
that the mercury emissions do not
exceed the emission limit. You must
also establish new operating limits
based on this performance test
according to the procedures in
§ 63.7530(b). You are not required to
conduct fuel analyses for the fuels
described in § 63.7510(a)(2)(i) through
(iii). You may exclude the fuels
described in § 63.7510(a)(2)(i) through
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(iii) when recalculating the mercury
emission rate.
(7) If your unit is controlled with a
fabric filter, and you demonstrate
continuous compliance using a bag leak
detection system, you must initiate
corrective action within 1 hour of a bag
leak detection system alert and
complete corrective actions as soon as
practical, and operate and maintain the
fabric filter system such that the periods
which would cause an alert are no more
than 5 percent of the operating time
during a 6-month period. You must also
keep records of the date, time, and
duration of each alert, the time
corrective action was initiated and
completed, and a brief description of the
cause of the alert and the corrective
action taken. You must also record the
percent of the operating time during
each 6-month period that the conditions
exist for an alert. In calculating this
operating time percentage, if inspection
of the fabric filter demonstrates that no
corrective action is required, no alert
time is counted. If corrective action is
required, each alert shall be counted as
a minimum of 1 hour. If you take longer
than 1 hour to initiate corrective action,
the alert time shall be counted as the
actual amount of time taken to initiate
corrective action.
(8) To demonstrate compliance with
the applicable alternative CO CEMS
emission limit listed in Tables 1, 2, or
11 through 13 to this subpart, you must
meet the requirements in paragraphs
(a)(8)(i) through (iv) of this section.
(i) Continuously monitor CO
according to §§ 63.7525(a) and 63.7535.
(ii) Maintain a CO emission level
below or at your applicable alternative
CO CEMS-based standard in Tables 1 or
2 or 11 through 13 to this subpart at all
times the affected unit is operating.
(iii) Keep records of CO levels
according to § 63.7555(b).
(iv) You must record and make
available upon request results of CO
CEMS performance audits, dates and
duration of periods when the CO CEMS
is out of control to completion of the
corrective actions necessary to return
the CO CEMS to operation consistent
with your site-specific monitoring plan.
(9) The owner or operator of a boiler
or process heater using a PM CPMS or
a PM CEMS to meet requirements of this
subpart shall install, certify, operate,
and maintain the PM CPMS or PM
CEMS in accordance with your sitespecific monitoring plan as required in
§ 63.7505(d).
(10) If your boiler or process heater
has a heat input capacity of 10 million
Btu per hour or greater, you must
conduct an annual tune-up of the boiler
or process heater to demonstrate
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continuous compliance as specified in
paragraphs (a)(10)(i) through (vi) of this
section. This frequency does not apply
to limited-use boilers and process
heaters, as defined in § 63.7575, or units
with continuous oxygen trim systems
that maintain an optimum air to fuel
ratio.
(i) As applicable, inspect the burner,
and clean or replace any components of
the burner as necessary (you may delay
the burner inspection until the next
scheduled unit shutdown). Units that
produce electricity for sale may delay
the burner inspection until the first
outage, not to exceed 36 months from
the previous inspection. At units where
entry into a piece of process equipment
or into a storage vessel is required to
complete the tune-up inspections,
inspections are required only during
planned entries into the storage vessel
or process equipment;
(ii) Inspect the flame pattern, as
applicable, and adjust the burner as
necessary to optimize the flame pattern.
The adjustment should be consistent
with the manufacturer’s specifications,
if available;
(iii) Inspect the system controlling the
air-to-fuel ratio, as applicable, and
ensure that it is correctly calibrated and
functioning properly (you may delay the
inspection until the next scheduled unit
shutdown). Units that produce
electricity for sale may delay the
inspection until the first outage, not to
exceed 36 months from the previous
inspection;
(iv) Optimize total emissions of CO.
This optimization should be consistent
with the manufacturer’s specifications,
if available, and with any NOX
requirement to which the unit is subject;
(v) Measure the concentrations in the
effluent stream of CO in parts per
million, by volume, and oxygen in
volume percent, before and after the
adjustments are made (measurements
may be either on a dry or wet basis, as
long as it is the same basis before and
after the adjustments are made).
Measurements may be taken using a
portable CO analyzer; and
(vi) Maintain on-site and submit, if
requested by the Administrator, an
annual report containing the
information in paragraphs (a)(10)(vi)(A)
through (C) of this section,
(A) The concentrations of CO in the
effluent stream in parts per million by
volume, and oxygen in volume percent,
measured at high fire or typical
operating load, before and after the
tune-up of the boiler or process heater;
(B) A description of any corrective
actions taken as a part of the tune-up;
and
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(C) The type and amount of fuel used
over the 12 months prior to the tune-up,
but only if the unit was physically and
legally capable of using more than one
type of fuel during that period. Units
sharing a fuel meter may estimate the
fuel used by each unit.
(11) If your boiler or process heater
has a heat input capacity of less than 10
million Btu per hour (except as
specified in paragraph (a)(12) of this
section), you must conduct a biennial
tune-up of the boiler or process heater
as specified in paragraphs (a)(10)(i)
through (vi) of this section to
demonstrate continuous compliance.
(12) If your boiler or process heater
has a continuous oxygen trim system
that maintains an optimum air to fuel
ratio, or a heat input capacity of less
than or equal to 5 million Btu per hour
and the unit is in the units designed to
burn gas 1; units designed to burn gas
2 (other); or units designed to burn light
liquid subcategories, or meets the
definition of limited-use boiler or
process heater in § 63.7575, you must
conduct a tune-up of the boiler or
process heater every 5 years as specified
in paragraphs (a)(10)(i) through (vi) of
this section to demonstrate continuous
compliance. You may delay the burner
inspection specified in paragraph
(a)(10)(i) of this section until the next
scheduled or unscheduled unit
shutdown, but you must inspect each
burner at least once every 72 months.
(13) If the unit is not operating on the
required date for a tune-up, the tune-up
must be conducted within 30 calendar
days of startup.
(14) If you are using a CEMS
measuring mercury emissions to meet
requirements of this subpart you must
install, certify, operate, and maintain
the mercury CEMS as specified in
paragraphs (a)(14)(i) and (ii) of this
section.
(i) Operate the mercury CEMS in
accordance with performance
specification 12A of 40 CFR part 60,
appendix B or operate a sorbent trap
based integrated monitor in accordance
with performance specification 12B of
40 CFR part 60, appendix B. The
duration of the performance test must be
the maximum of 30 unit operating days
or 720 hours. For each day in which the
unit operates, you must obtain hourly
mercury concentration data, and stack
gas volumetric flow rate data.
(ii) If you are using a mercury CEMS,
you must install, operate, calibrate, and
maintain an instrument for
continuously measuring and recording
the mercury mass emissions rate to the
atmosphere according to the
requirements of performance
specifications 6 and 12A of 40 CFR part
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60, appendix B, and quality assurance
procedure 6 of 40 CFR part 60, appendix
F.
(15) If you are using a CEMS to
measure HCl emissions to meet
requirements of this subpart, you must
install, certify, operate, and maintain
the HCl CEMS as specified in
paragraphs (a)(15)(i) and (ii) of this
section. This option for an affected unit
takes effect on the date a final
performance specification for an HCl
CEMS is published in the Federal
Register or the date of approval of a sitespecific monitoring plan.
(i) Operate the continuous emissions
monitoring system in accordance with
the applicable performance
specification in 40 CFR part 60,
appendix B. The duration of the
performance test must be the maximum
of 30 unit operating days or 720 hours.
For each day in which the unit operates,
you must obtain hourly HCl
concentration data, and stack gas
volumetric flow rate data.
(ii) If you are using a HCl CEMS, you
must install, operate, calibrate, and
maintain an instrument for
continuously measuring and recording
the HCl mass emissions rate to the
atmosphere according to the
requirements of the applicable
performance specification of 40 CFR
part 60, appendix B, and the quality
assurance procedures of 40 CFR part 60,
appendix F.
(16) If you demonstrate compliance
with an applicable TSM emission limit
through performance testing, and you
plan to burn a new type of fuel or a new
mixture of fuels, you must recalculate
the maximum TSM input using
Equation 9 of § 63.7530. If the results of
recalculating the maximum TSM input
using Equation 9 of § 63.7530 are higher
than the maximum total selected input
level established during the previous
performance test, then you must
conduct a new performance test within
60 days of burning the new fuel type or
fuel mixture according to the
procedures in § 63.7520 to demonstrate
that the TSM emissions do not exceed
the emission limit. You must also
establish new operating limits based on
this performance test according to the
procedures in § 63.7530(b). You are not
required to conduct fuel analyses for the
fuels described in § 63.7510(a)(2)(i)
through (iii). You may exclude the fuels
described in § 63.7510(a)(2)(i) through
(iii) when recalculating the TSM
emission rate.
(17) If you demonstrate compliance
with an applicable TSM emission limit
through fuel analysis for solid or liquid
fuels, and you plan to burn a new type
of fuel, you must recalculate the TSM
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emission rate using Equation 14 of
§ 63.7530 according to the procedures
specified in paragraphs (a)(5)(i) through
(iii) of this section. You are not required
to conduct fuel analyses for the fuels
described in § 63.7510(a)(2)(i) through
(iii). You may exclude the fuels
described in § 63.7510(a)(2)(i) through
(iii) when recalculating the TSM
emission rate.
(i) You must determine the TSM
concentration for any new fuel type in
units of pounds per million Btu, based
on supplier data or your own fuel
analysis, according to the provisions in
your site-specific fuel analysis plan
developed according to § 63.7521(b).
(ii) You must determine the new
mixture of fuels that will have the
highest content of TSM.
(iii) Recalculate the TSM emission
rate from your boiler or process heater
under these new conditions using
Equation 14 of § 63.7530. The
recalculated TSM emission rate must be
less than the applicable emission limit.
(18) If you demonstrate continuous
PM emissions compliance with a PM
CPMS you will use a PM CPMS to
establish a site-specific operating limit
corresponding to the results of the
performance test demonstrating
compliance with the PM limit. You will
conduct your performance test using the
test method criteria in Table 5 of this
subpart. You will use the PM CPMS to
demonstrate continuous compliance
with this operating limit. You must
repeat the performance test annually
and reassess and adjust the site-specific
operating limit in accordance with the
results of the performance test.
(i) To determine continuous
compliance, you must record the PM
CPMS output data for all periods when
the process is operating and the PM
CPMS is not out-of-control. You must
demonstrate continuous compliance by
using all quality-assured hourly average
data collected by the PM CPMS for all
operating hours to calculate the
arithmetic average operating parameter
in units of the operating limit
(milliamps) on a 30-day rolling average
basis, updated at the end of each new
boiler or process heater operating hour.
(ii) For any deviation of the 30-day
rolling PM CPMS average value from the
established operating parameter limit,
you must:
(A) Within 48 hours of the deviation,
visually inspect the air pollution control
device (APCD);
(B) If inspection of the APCD
identifies the cause of the deviation,
take corrective action as soon as
possible and return the PM CPMS
measurement to within the established
value; and
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(C) Within 30 days of the deviation or
at the time of the annual compliance
test, whichever comes first, conduct a
PM emissions compliance test to
determine compliance with the PM
emissions limit and to verify or reestablish the CPMS operating limit. You
are not required to conduct additional
testing for any deviations that occur
between the time of the original
deviation and the PM emissions
compliance test required under this
paragraph.
(iii) PM CPMS deviations from the
operating limit leading to more than
four required performance tests in a 12month operating period constitute a
separate violation of this subpart.
(19) If you choose to comply with the
PM filterable emissions limit by using
PM CEMS you must install, certify,
operate, and maintain a PM CEMS and
record the output of the PM CEMS as
specified in paragraphs (a)(19)(i)
through (vii) of this section. The
compliance limit will be expressed as a
30-day rolling average of the numerical
emissions limit value applicable for
your unit in Tables 1 or 2 or 11 through
13 of this subpart.
(i) Install and certify your PM CEMS
according to the procedures and
requirements in Performance
Specification 11—Specifications and
Test Procedures for Particulate Matter
Continuous Emission Monitoring
Systems at Stationary Sources in
Appendix B to part 60 of this chapter,
using test criteria outlined in Table V of
this rule. The reportable measurement
output from the PM CEMS must be
expressed in units of the applicable
emissions limit (e.g., lb/MMBtu, lb/
MWh).
(ii) Operate and maintain your PM
CEMS according to the procedures and
requirements in Procedure 2— Quality
Assurance Requirements for Particulate
Matter Continuous Emission Monitoring
Systems at Stationary Sources in
Appendix F to part 60 of this chapter.
(A) You must conduct the relative
response audit (RRA) for your PM CEMS
at least once annually.
(B) You must conduct the relative
correlation audit (RCA) for your PM
CEMS at least once every 3 years.
(iii) Collect PM CEMS hourly average
output data for all boiler operating
hours except as indicated in paragraph
(i) of this section.
(iv) Calculate the arithmetic 30-day
rolling average of all of the hourly
average PM CEMS output data collected
during all nonexempt boiler or process
heater operating hours.
(v) You must collect data using the
PM CEMS at all times the unit is
operating and at the intervals specified
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this paragraph (a), except for periods of
monitoring system malfunctions, repairs
associated with monitoring system
malfunctions, and required monitoring
system quality assurance or quality
control activities.
(vi) You must use all the data
collected during all boiler or process
heater operating hours in assessing the
compliance with your operating limit
except:
(A) Any data collected during
monitoring system malfunctions, repairs
associated with monitoring system
malfunctions, or required monitoring
system quality assurance or control
activities conducted during monitoring
system malfunctions in calculations and
report any such periods in your annual
deviation report;
(B) Any data collected during periods
when the monitoring system is out of
control as specified in your site-specific
monitoring plan, repairs associated with
periods when the monitoring system is
out of control, or required monitoring
system quality assurance or control
activities conducted during out of
control periods in calculations used to
report emissions or operating levels and
report any such periods in your annual
deviation report;
(C) Any data recorded during periods
of startup or shutdown.
(vii) You must record and make
available upon request results of PM
CEMS system performance audits, dates
and duration of periods when the PM
CEMS is out of control to completion of
the corrective actions necessary to
return the PM CEMS to operation
consistent with your site-specific
monitoring plan.
(b) You must report each instance in
which you did not meet each emission
limit and operating limit in Tables 1
through 4 or 11 through 13 to this
subpart that apply to you. These
instances are deviations from the
emission limits or operating limits,
respectively, in this subpart. These
deviations must be reported according
to the requirements in § 63.7550.
(c) If you elected to demonstrate that
the unit meets the specification for
mercury for the unit designed to burn
gas 1 subcategory, you must follow the
sampling frequency specified in
paragraphs (c)(1) through (4) of this
section and conduct this sampling
according to the procedures in
§ 63.7521(f) through (i).
(1) If the initial mercury constituents
in the gaseous fuels are measured to be
equal to or less than half of the mercury
specification as defined in § 63.7575,
you do not need to conduct further
sampling.
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(2) If the initial mercury constituents
are greater than half but equal to or less
than 75 percent of the mercury
specification as defined in § 63.7575,
you will conduct semi-annual sampling.
If 6 consecutive semi-annual fuel
analyses demonstrate 50 percent or less
of the mercury specification, you do not
need to conduct further sampling. If any
semi-annual sample exceeds 75 percent
of the mercury specification, you must
return to monthly sampling for that fuel,
until 12 months of fuel analyses again
are less than 75 percent of the
compliance level.
(3) If the initial mercury constituents
are greater than 75 percent of the
mercury specification as defined in
§ 63.7575, you will conduct monthly
sampling. If 12 consecutive monthly
fuel analyses demonstrate 75 percent or
less of the mercury specification, you
may decrease the fuel analysis
frequency to semi-annual for that fuel.
(4) If the initial sample exceeds the
mercury specification as defined in
§ 63.7575, each affected boiler or
process heater combusting this fuel is
not part of the unit designed to burn gas
1 subcategory and must be in
compliance with the emission and
operating limits for the appropriate
subcategory. You may elect to conduct
additional monthly sampling while
complying with these emissions and
operating limits to demonstrate that the
fuel qualifies as another gas 1 fuel. If 12
consecutive monthly fuel analyses
samples are at or below the mercury
specification as defined in § 63.7575,
each affected boiler or process heater
combusting the fuel can elect to switch
back into the unit designed to burn gas
1 subcategory until the mercury
specification is exceeded.
(d) For startup and shutdown, you
must meet the work practice standards
according to item 5 of Table 3 of this
subpart.
■ 22. Section 63.7541 is amended by
revising paragraphs (a)(3) and (4) to read
as follows:
§ 63.7541 How do I demonstrate
continuous compliance under the
emissions averaging provision?
*
*
*
*
*
(a) * * *
(3) For each existing unit participating
in the emissions averaging option that is
equipped with a wet scrubber, maintain
the 30-day rolling average parameter
values at or above the operating limits
established during the most recent
performance test.
(4) For each existing unit participating
in the emissions averaging option that
has an approved alternative operating
parameter, maintain the 30-day rolling
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average parameter values consistent
with the approved monitoring plan.
*
*
*
*
*
■ 23. Section 63.7545 is amended by:
■ a. Revising paragraphs (a) through (c).
■ b. Revising paragraphs (e)
introductory text, (e)(1), (e)(2), (e)(3),
(e)(4), (e)(5) introductory text, and
(e)(5)(i).
■ c. Adding paragraph (e)(5)(ii).
■ d. Revising paragraphs (e)(8)(i) and
(iii).
■ e. Revising paragraph (f) introductory
text.
■ f. Revising paragraphs (g)(1) and (2).
■ g. Revising paragraphs (h)
introductory text and (h)(1) and (3).
■ h. Removing paragraph (h)(4).
The revisions and addition read as
follows:
tkelley on DSK3SPTVN1PROD with
§ 63.7545 What notifications must I submit
and when?
(a) You must submit to the
Administrator all of the notifications in
§§ 63.7(b) and (c), 63.8(e), (f)(4) and (6),
and 63.9(b) through (h) that apply to
you by the dates specified.
(b) As specified in § 63.9(b)(2), if you
startup your affected source before
January 31, 2013, you must submit an
Initial Notification not later than 120
days after January 31, 2013.
(c) As specified in § 63.9(b)(4) and (5),
if you startup your new or reconstructed
affected source on or after January 31,
2013, you must submit an Initial
Notification not later than 15 days after
the actual date of startup of the affected
source.
*
*
*
*
*
(e) If you are required to conduct an
initial compliance demonstration as
specified in § 63.7530, you must submit
a Notification of Compliance Status
according to § 63.9(h)(2)(ii). For the
initial compliance demonstration for
each boiler or process heater, you must
submit the Notification of Compliance
Status, including all performance test
results and fuel analyses, before the
close of business on the 60th day
following the completion of all
performance test and/or other initial
compliance demonstrations for all boiler
or process heaters at the facility
according to § 63.10(d)(2). The
Notification of Compliance Status report
must contain all the information
specified in paragraphs (e)(1) through
(8), as applicable. If you are not required
to conduct an initial compliance
demonstration as specified in
§ 63.7530(a), the Notification of
Compliance Status must only contain
the information specified in paragraphs
(e)(1) and (8).
(1) A description of the affected
unit(s) including identification of which
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subcategories the unit is in, the design
heat input capacity of the unit, a
description of the add-on controls used
on the unit to comply with this subpart,
description of the fuel(s) burned,
including whether the fuel(s) were a
secondary material determined by you
or the EPA through a petition process to
be a non-waste under § 241.3 of this
chapter, whether the fuel(s) were a
secondary material processed from
discarded non-hazardous secondary
materials within the meaning of § 241.3
of this chapter, and justification for the
selection of fuel(s) burned during the
compliance demonstration.
(2) Summary of the results of all
performance tests and fuel analyses, and
calculations conducted to demonstrate
initial compliance including all
established operating limits, and
including:
(i) Identification of whether you are
complying with the PM emission limit
or the alternative TSM emission limit.
(ii) Identification of whether you are
complying with the output-based
emission limits or the heat input-based
(i.e., lb/MMBtu or ppm) emission limits,
(3) A summary of the maximum CO
emission levels recorded during the
performance test to show that you have
met any applicable emission standard in
Tables 1, 2, or 11 through 13 to this
subpart, if you are not using a CO CEMS
to demonstrate compliance.
(4) Identification of whether you plan
to demonstrate compliance with each
applicable emission limit through
performance testing, a CEMS, or fuel
analysis.
(5) Identification of whether you plan
to demonstrate compliance by emissions
averaging and identification of whether
you plan to demonstrate compliance by
using efficiency credits through energy
conservation:
(i) If you plan to demonstrate
compliance by emission averaging,
report the emission level that was being
achieved or the control technology
employed on January 31, 2013.
(ii) [Reserved]
*
*
*
*
*
(8) * * *
(i) ‘‘This facility complies with the
required initial tune-up according to the
procedures in § 63.7540(a)(10)(i)
through (vi).’’
*
*
*
*
*
(iii) Except for units that burn only
natural gas, refinery gas, or other gas 1
fuel, or units that qualify for a statutory
exemption as provided in section
129(g)(1) of the Clean Air Act, include
the following: ‘‘No secondary materials
that are solid waste were combusted in
any affected unit.’’
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7183
(f) If you operate a unit designed to
burn natural gas, refinery gas, or other
gas 1 fuels that is subject to this subpart,
and you intend to use a fuel other than
natural gas, refinery gas, gaseous fuel
subject to another subpart of this part,
part 60, 61, or 65, or other gas 1 fuel to
fire the affected unit during a period of
natural gas curtailment or supply
interruption, as defined in § 63.7575,
you must submit a notification of
alternative fuel use within 48 hours of
the declaration of each period of natural
gas curtailment or supply interruption,
as defined in § 63.7575. The notification
must include the information specified
in paragraphs (f)(1) through (5) of this
section.
*
*
*
*
*
(g) * * *
(1) The name of the owner or operator
of the affected source, as defined in
§ 63.7490, the location of the source, the
boiler(s) or process heater(s) that will
commence burning solid waste, and the
date of the notice.
(2) The currently applicable
subcategories under this subpart.
*
*
*
*
*
(h) If you have switched fuels or made
a physical change to the boiler and the
fuel switch or physical change resulted
in the applicability of a different
subcategory, you must provide notice of
the date upon which you switched fuels
or made the physical change within 30
days of the switch/change. The
notification must identify:
(1) The name of the owner or operator
of the affected source, as defined in
§ 63.7490, the location of the source, the
boiler(s) and process heater(s) that have
switched fuels, were physically
changed, and the date of the notice.
*
*
*
*
*
(3) The date upon which the fuel
switch or physical change occurred.
■ 24. Section 63.7550 is revised to read
as follows:
§ 63.7550
when?
What reports must I submit and
(a) You must submit each report in
Table 9 to this subpart that applies to
you.
(b) Unless the EPA Administrator has
approved a different schedule for
submission of reports under § 63.10(a),
you must submit each report, according
to paragraph (h) of this section, by the
date in Table 9 to this subpart and
according to the requirements in
paragraphs (b)(1) through (4) of this
section. For units that are subject only
to a requirement to conduct an annual,
biennial, or 5-year tune-up according to
§ 63.7540(a)(10), (11), or (12),
respectively, and not subject to emission
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limits or operating limits, you may
submit only an annual, biennial, or 5year compliance report, as applicable, as
specified in paragraphs (b)(1) through
(4) of this section, instead of a semiannual compliance report.
(1) The first compliance report must
cover the period beginning on the
compliance date that is specified for
each boiler or process heater in
§ 63.7495 and ending on July 31 or
January 31, whichever date is the first
date that occurs at least 180 days (or 1,
2, or 5 years, as applicable, if submitting
an annual, biennial, or 5-year
compliance report) after the compliance
date that is specified for your source in
§ 63.7495.
(2) The first compliance report must
be postmarked or submitted no later
than July 31 or January 31, whichever
date is the first date following the end
of the first calendar half after the
compliance date that is specified for
each boiler or process heater in
§ 63.7495. The first annual, biennial, or
5-year compliance report must be
postmarked or submitted no later than
January 31.
(3) Each subsequent compliance
report must cover the semiannual
reporting period from January 1 through
June 30 or the semiannual reporting
period from July 1 through December
31. Annual, biennial, and 5-year
compliance reports must cover the
applicable 1-, 2-, or 5-year periods from
January 1 to December 31.
(4) Each subsequent compliance
report must be postmarked or submitted
no later than July 31 or January 31,
whichever date is the first date
following the end of the semiannual
reporting period. Annual, biennial, and
5-year compliance reports must be
postmarked or submitted no later than
January 31.
(c) A compliance report must contain
the following information depending on
how the facility chooses to comply with
the limits set in this rule.
(1) If the facility is subject to a the
requirements of a tune up they must
submit a compliance report with the
information in paragraphs (c)(5)(i)
through (iv) and (xiv) of this section.
(2) If a facility is complying with the
fuel analysis they must submit a
compliance report with the information
in paragraphs (c)(5)(i) through (iv), (vi),
(x), (xi), (xiii), (xv) and paragraph (d) of
this section.
(3) If a facility is complying with the
applicable emissions limit with
performance testing they must submit a
compliance report with the information
in (c)(5)(i) through (iv), (vi), (vii), (ix),
(xi), (xiii), (xv) and paragraph (d) of this
section.
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(4) If a facility is complying with an
emissions limit using a CMS the
compliance report must contain the
information required in paragraphs
(c)(5)(i) through (vi), (xi), (xiii), (xv)
through (xvii), and paragraph (e) of this
section.
(5)(i) Company and Facility name and
address.
(ii) Process unit information,
emissions limitations, and operating
parameter limitations.
(iii) Date of report and beginning and
ending dates of the reporting period.
(iv) The total operating time during
the reporting period.
(v) If you use a CMS, including CEMS,
COMS, or CPMS, you must include the
monitoring equipment manufacturer(s)
and model numbers and the date of the
last CMS certification or audit.
(vi) The total fuel use by each
individual boiler or process heater
subject to an emission limit within the
reporting period, including, but not
limited to, a description of the fuel,
whether the fuel has received a nonwaste determination by the EPA or your
basis for concluding that the fuel is not
a waste, and the total fuel usage amount
with units of measure.
(vii) If you are conducting
performance tests once every 3 years
consistent with § 63.7515(b) or (c), the
date of the last 2 performance tests and
a statement as to whether there have
been any operational changes since the
last performance test that could increase
emissions.
(viii) A statement indicating that you
burned no new types of fuel in an
individual boiler or process heater
subject to an emission limit. Or, if you
did burn a new type of fuel and are
subject to a HCl emission limit, you
must submit the calculation of chlorine
input, using Equation 7 of § 63.7530,
that demonstrates that your source is
still within its maximum chlorine input
level established during the previous
performance testing (for sources that
demonstrate compliance through
performance testing) or you must submit
the calculation of HCl emission rate
using Equation 12 of § 63.7530 that
demonstrates that your source is still
meeting the emission limit for HCl
emissions (for boilers or process heaters
that demonstrate compliance through
fuel analysis). If you burned a new type
of fuel and are subject to a mercury
emission limit, you must submit the
calculation of mercury input, using
Equation 8 of § 63.7530, that
demonstrates that your source is still
within its maximum mercury input
level established during the previous
performance testing (for sources that
demonstrate compliance through
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performance testing), or you must
submit the calculation of mercury
emission rate using Equation 13 of
§ 63.7530 that demonstrates that your
source is still meeting the emission limit
for mercury emissions (for boilers or
process heaters that demonstrate
compliance through fuel analysis). If
you burned a new type of fuel and are
subject to a TSM emission limit, you
must submit the calculation of TSM
input, using Equation 9 of § 63.7530,
that demonstrates that your source is
still within its maximum TSM input
level established during the previous
performance testing (for sources that
demonstrate compliance through
performance testing), or you must
submit the calculation of TSM emission
rate, using Equation 14 of § 63.7530, that
demonstrates that your source is still
meeting the emission limit for TSM
emissions (for boilers or process heaters
that demonstrate compliance through
fuel analysis).
(ix) If you wish to burn a new type of
fuel in an individual boiler or process
heater subject to an emission limit and
you cannot demonstrate compliance
with the maximum chlorine input
operating limit using Equation 7 of
§ 63.7530 or the maximum mercury
input operating limit using Equation 8
of § 63.7530, or the maximum TSM
input operating limit using Equation 9
of § 63.7530 you must include in the
compliance report a statement
indicating the intent to conduct a new
performance test within 60 days of
starting to burn the new fuel.
(x) A summary of any monthly fuel
analyses conducted to demonstrate
compliance according to §§ 63.7521 and
63.7530 for individual boilers or process
heaters subject to emission limits, and
any fuel specification analyses
conducted according to §§ 63.7521(f)
and 63.7530(g).
(xi) If there are no deviations from any
emission limits or operating limits in
this subpart that apply to you, a
statement that there were no deviations
from the emission limits or operating
limits during the reporting period.
(xii) If there were no deviations from
the monitoring requirements including
no periods during which the CMSs,
including CEMS, COMS, and CPMS,
were out of control as specified in
§ 63.8(c)(7), a statement that there were
no deviations and no periods during
which the CMS were out of control
during the reporting period.
(xiii) If a malfunction occurred during
the reporting period, the report must
include the number, duration, and a
brief description for each type of
malfunction which occurred during the
reporting period and which caused or
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may have caused any applicable
emission limitation to be exceeded. The
report must also include a description of
actions taken by you during a
malfunction of a boiler, process heater,
or associated air pollution control
device or CMS to minimize emissions in
accordance with § 63.7500(a)(3),
including actions taken to correct the
malfunction.
(xiv) Include the date of the most
recent tune-up for each unit subject to
only the requirement to conduct an
annual, biennial, or 5-year tune-up
according to § 63.7540(a)(10), (11), or
(12) respectively. Include the date of the
most recent burner inspection if it was
not done annually, biennially, or on a 5year period and was delayed until the
next scheduled or unscheduled unit
shutdown.
(xv) If you plan to demonstrate
compliance by emission averaging,
certify the emission level achieved or
the control technology employed is no
less stringent than the level or control
technology contained in the notification
of compliance status in
§ 63.7545(e)(5)(i).
(xvi) For each reporting period, the
compliance reports must include all of
the calculated 30 day rolling average
values based on the daily CEMS (CO
and mercury) and CPMS (PM CPMS
output, scrubber pH, scrubber liquid
flow rate, scrubber pressure drop) data.
(xvii) Statement by a responsible
official with that official’s name, title,
and signature, certifying the truth,
accuracy, and completeness of the
content of the report.
(d) For each deviation from an
emission limit or operating limit in this
subpart that occurs at an individual
boiler or process heater where you are
not using a CMS to comply with that
emission limit or operating limit, the
compliance report must additionally
contain the information required in
paragraphs (d)(1) through (3) of this
section.
(1) A description of the deviation and
which emission limit or operating limit
from which you deviated.
(2) Information on the number,
duration, and cause of deviations
(including unknown cause), as
applicable, and the corrective action
taken.
(3) If the deviation occurred during an
annual performance test, provide the
date the annual performance test was
completed.
(e) For each deviation from an
emission limit, operating limit, and
monitoring requirement in this subpart
occurring at an individual boiler or
process heater where you are using a
CMS to comply with that emission limit
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or operating limit, the compliance
report must additionally contain the
information required in paragraphs
(e)(1) through (9) of this section. This
includes any deviations from your sitespecific monitoring plan as required in
§ 63.7505(d).
(1) The date and time that each
deviation started and stopped and
description of the nature of the
deviation (i.e., what you deviated from).
(2) The date and time that each CMS
was inoperative, except for zero (lowlevel) and high-level checks.
(3) The date, time, and duration that
each CMS was out of control, including
the information in § 63.8(c)(8).
(4) The date and time that each
deviation started and stopped.
(5) A summary of the total duration of
the deviation during the reporting
period and the total duration as a
percent of the total source operating
time during that reporting period.
(6) A characterization of the total
duration of the deviations during the
reporting period into those that are due
to control equipment problems, process
problems, other known causes, and
other unknown causes.
(7) A summary of the total duration of
CMS’s downtime during the reporting
period and the total duration of CMS
downtime as a percent of the total
source operating time during that
reporting period.
(8) A brief description of the source
for which there was a deviation.
(9) A description of any changes in
CMSs, processes, or controls since the
last reporting period for the source for
which there was a deviation.
(f) [Reserved]
(g) [Reserved]
(h) You must submit the reports
according to the procedures specified in
paragraphs (h)(1) through (3) of this
section.
(1) Within 60 days after the date of
completing each performance test
(defined in § 63.2) as required by this
subpart you must submit the results of
the performance tests, including any
associated fuel analyses, required by
this subpart and the compliance reports
required in § 63.7550(b) to the EPA’s
WebFIRE database by using the
Compliance and Emissions Data
Reporting Interface (CEDRI) that is
accessed through the EPA’s Central Data
Exchange (CDX) (www.epa.gov/cdx).
Performance test data must be submitted
in the file format generated through use
of the EPA’s Electronic Reporting Tool
(ERT) (see https://www.epa.gov/ttn/chief/
ert/). Only data collected
using test methods on the ERT Web site
are subject to this requirement for
submitting reports electronically to
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7185
WebFIRE. Owners or operators who
claim that some of the information being
submitted for performance tests is
confidential business information (CBI)
must submit a complete ERT file
including information claimed to be CBI
on a compact disk or other commonly
used electronic storage media
(including, but not limited to, flash
drives) to the EPA. The electronic media
must be clearly marked as CBI and
mailed to U.S. EPA/OAPQS/CORE CBI
Office, Attention: WebFIRE
Administrator, MD C404–02, 4930 Old
Page Rd., Durham, NC 27703. The same
ERT file with the CBI omitted must be
submitted to the EPA via CDX as
described earlier in this paragraph. At
the discretion of the Administrator, you
must also submit these reports,
including the confidential business
information, to the Administrator in the
format specified by the Administrator.
For any performance test conducted
using test methods that are not listed on
the ERT Web site, the owner or operator
shall submit the results of the
performance test in paper submissions
to the Administrator.
(2) Within 60 days after the date of
completing each CEMS performance
evaluation test (defined in 63.2) you
must submit the relative accuracy test
audit (RATA) data to the EPA’s Central
Data Exchange by using CEDRI as
mentioned in paragraph (h)(1) of this
section. Only RATA pollutants that can
be documented with the ERT (as listed
on the ERT Web site) are subject to this
requirement. For any performance
evaluations with no corresponding
RATA pollutants listed on the ERT Web
site, the owner or operator shall submit
the results of the performance
evaluation in paper submissions to the
Administrator.
(3) You must submit all reports
required by Table 9 of this subpart
electronically using CEDRI that is
accessed through the EPA’s Central Data
Exchange (CDX) (www.epa.gov/cdx).
However, if the reporting form specific
to this subpart is not available in CEDRI
at the time that the report is due the
report you must submit the report to the
Administrator at the appropriate
address listed in § 63.13. At the
discretion of the Administrator, you
must also submit these reports, to the
Administrator in the format specified by
the Administrator.
■ 25. Section 63.7555 is amended by:
■ a. Revising paragraphs (d)
introductory text and (d)(2) through (6).
■ b. Adding paragraphs (d)(9) through
(11).
■ c. Revising paragraphs (f) through (h).
■ d. Adding paragraphs (i) and (j).
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The revisions and additions read as
follows:
§ 63.7555
What records must I keep?
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*
*
*
*
*
(d) For each boiler or process heater
subject to an emission limit in Tables 1,
2, or 11 through 13 to this subpart, you
must also keep the applicable records in
paragraphs (d)(1) through (11) of this
section.
*
*
*
*
*
(2) If you combust non-hazardous
secondary materials that have been
determined not to be solid waste
pursuant to § 241.3(b)(1) and (2) of this
chapter, you must keep a record that
documents how the secondary material
meets each of the legitimacy criteria
under § 241.3(d)(1) of this chapter. If
you combust a fuel that has been
processed from a discarded nonhazardous secondary material pursuant
to § 241.3(b)(4) of this chapter, you must
keep records as to how the operations
that produced the fuel satisfy the
definition of processing in § 241.2 of
this chapter. If the fuel received a nonwaste determination pursuant to the
petition process submitted under
§ 241.3(c) of this chapter, you must keep
a record that documents how the fuel
satisfies the requirements of the petition
process. For operating units that
combust non-hazardous secondary
materials as fuel per § 241.4 of this
chapter, you must keep records
documenting that the material is listed
as a non-waste under § 241.4(a) of this
chapter. Units exempt from the
incinerator standards under section
129(g)(1) of the Clean Air Act because
they are qualifying facilities burning a
homogeneous waste stream do not need
to maintain the records described in this
paragraph (d)(2).
(3) For units in the limited use
subcategory, you must keep a copy of
the federally enforceable permit that
limits the annual capacity factor to less
than or equal to 10 percent and fuel use
records for the days the boiler or process
heater was operating.
(4) A copy of all calculations and
supporting documentation of maximum
chlorine fuel input, using Equation 7 of
§ 63.7530, that were done to
demonstrate continuous compliance
with the HCl emission limit, for sources
that demonstrate compliance through
performance testing. For sources that
demonstrate compliance through fuel
analysis, a copy of all calculations and
supporting documentation of HCl
emission rates, using Equation 12 of
§ 63.7530, that were done to
demonstrate compliance with the HCl
emission limit. Supporting
documentation should include results of
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any fuel analyses and basis for the
estimates of maximum chlorine fuel
input or HCl emission rates. You can
use the results from one fuel analysis for
multiple boilers and process heaters
provided they are all burning the same
fuel type. However, you must calculate
chlorine fuel input, or HCl emission
rate, for each boiler and process heater.
(5) A copy of all calculations and
supporting documentation of maximum
mercury fuel input, using Equation 8 of
§ 63.7530, that were done to
demonstrate continuous compliance
with the mercury emission limit for
sources that demonstrate compliance
through performance testing. For
sources that demonstrate compliance
through fuel analysis, a copy of all
calculations and supporting
documentation of mercury emission
rates, using Equation 13 of § 63.7530,
that were done to demonstrate
compliance with the mercury emission
limit. Supporting documentation should
include results of any fuel analyses and
basis for the estimates of maximum
mercury fuel input or mercury emission
rates. You can use the results from one
fuel analysis for multiple boilers and
process heaters provided they are all
burning the same fuel type. However,
you must calculate mercury fuel input,
or mercury emission rates, for each
boiler and process heater.
(6) If, consistent with § 63.7515(b),
you choose to stack test less frequently
than annually, you must keep a record
that documents that your emissions in
the previous stack test(s) were less than
75 percent of the applicable emission
limit (or, in specific instances noted in
Tables 1 and 2 or 11 through 13 to this
subpart, less than the applicable
emission limit), and document that
there was no change in source
operations including fuel composition
and operation of air pollution control
equipment that would cause emissions
of the relevant pollutant to increase
within the past year.
*
*
*
*
*
(9) A copy of all calculations and
supporting documentation of maximum
TSM fuel input, using Equation 9 of
§ 63.7530, that were done to
demonstrate continuous compliance
with the TSM emission limit for sources
that demonstrate compliance through
performance testing. For sources that
demonstrate compliance through fuel
analysis, a copy of all calculations and
supporting documentation of TSM
emission rates, using Equation 14 of
§ 63.7530, that were done to
demonstrate compliance with the TSM
emission limit. Supporting
documentation should include results of
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any fuel analyses and basis for the
estimates of maximum TSM fuel input
or TSM emission rates. You can use the
results from one fuel analysis for
multiple boilers and process heaters
provided they are all burning the same
fuel type. However, you must calculate
TSM fuel input, or TSM emission rates,
for each boiler and process heater.
(10) You must maintain records of the
calendar date, time, occurrence and
duration of each startup and shutdown.
(11) You must maintain records of the
type(s) and amount(s) of fuels used
during each startup and shutdown.
*
*
*
*
*
(f) If you elect to use efficiency credits
from energy conservation measures to
demonstrate compliance according to
§ 63.7533, you must keep a copy of the
Implementation Plan required in
§ 63.7533(d) and copies of all data and
calculations used to establish credits
according to § 63.7533(b), (c), and (f).
(g) If you elected to demonstrate that
the unit meets the specification for
mercury for the unit designed to burn
gas 1 subcategory, you must maintain
monthly records (or at the frequency
required by § 63.7540(c)) of the
calculations and results of the fuel
specification for mercury in Table 6.
(h) If you operate a unit in the unit
designed to burn gas 1 subcategory that
is subject to this subpart, and you use
an alternative fuel other than natural
gas, refinery gas, gaseous fuel subject to
another subpart under this part, other
gas 1 fuel, or gaseous fuel subject to
another subpart of this part or part 60,
61, or 65, you must keep records of the
total hours per calendar year that
alternative fuel is burned and the total
hours per calendar year that the unit
operated during periods of gas
curtailment or gas supply emergencies.
(i) You must maintain records of the
calendar date, time, occurrence and
duration of each startup and shutdown.
(j) You must maintain records of the
type(s) and amount(s) of fuels used
during each startup and shutdown.
■ 26. Section 63.7570 is amended by
revising paragraph (a) and paragraph (b)
introductory text to read as follows:
§ 63.7570 Who implements and enforces
this subpart?
(a) This subpart can be implemented
and enforced by the EPA, or an
Administrator such as your state, local,
or tribal agency. If the EPA
Administrator has delegated authority to
your state, local, or tribal agency, then
that agency (as well as the EPA) has the
authority to implement and enforce this
subpart. You should contact your EPA
Regional Office to find out if this
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subpart is delegated to your state, local,
or tribal agency.
(b) In delegating implementation and
enforcement authority of this subpart to
a state, local, or tribal agency under 40
CFR part 63, subpart E, the authorities
listed in paragraphs (b)(1) through (5) of
this section are retained by the EPA
Administrator and are not transferred to
the state, local, or tribal agency,
however, the EPA retains oversight of
this subpart and can take enforcement
actions, as appropriate.
*
*
*
*
*
■ 27. Section 63.7575 is amended by:
■ a. Adding in alphabetical order
definitions for ‘‘10-day rolling average,’’
‘‘30-day rolling average,’’ ‘‘Annual
capacity factor,’’ ‘‘Average annual heat
input rate,’’ ‘‘Benchmark,’’ ‘‘Biodiesel,’’
‘‘Daily block average,’’ ‘‘Efficiency
credit,’’ ‘‘Energy management program,’’
‘‘Fluidized bed boiler with an integrated
fluidized bed heat exchanger,’’ ‘‘Heavy
liquid,’’ ‘‘Light liquid,’’ ’’ ‘‘Major source
for oil and natural gas production
facilities,’’ ‘‘Minimum oxygen level,’’
‘‘Other combustor’’, ‘‘Oxygen analyzer
system’’, ‘‘Oxygen trim system’’, ‘‘Pile
burner’’, ‘‘Regulated gas stream’’,
‘‘Residential boiler,’’ ‘‘Residual oil’’,
‘‘Secondary material,’’ ‘‘Shutdown’’,
‘‘Sloped grate’’, ‘‘Startup’’, ‘‘Stoker/
sloped grate/other unit designed to burn
kiln dried biomass,’’ Stoker/sloped
grate/other unit designed to burn wet
biomass,’’ ‘‘Suspension burner,’’ ‘‘Total
selected metals (TSM),’’ ‘‘Traditional
fuel,’’ ‘‘Ultra low sulfur liquid fuel,’’
‘‘Unit designed to burn heavy liquid
subcategory,’’ ‘‘Unit designed to burn
light liquid subcategory,’’ and
‘‘Vegetable oil.’’
■ b. Revising the definitions for
‘‘Boiler,’’ ‘‘Boiler system,’’ ‘‘Coal,’’
Commercial/institutional boiler,’’
‘‘Deviation,’’ ‘‘Distillate oil,’’ ‘‘Dry
scrubber,’’ ‘‘Dutch oven,’’ ‘‘Electric
utility steam generating unit,’’ ‘‘Energy
assessment,’’ ‘‘Energy use system,’’
‘‘Equivalent,’’ ‘‘Federally enforceable,’’
‘‘Fluidized bed boiler’’, ‘‘Fuel cell,’’
‘‘Fuel type,’’ ‘‘Gaseous fuel,’’ ‘‘Heat
input,’’ ‘‘Hot water heater,’’ ‘‘Hybrid
suspension grate boiler,’’ ‘‘Industrial
boiler,’’ ‘‘Limited-use boiler or process
heater,’’ ‘‘Liquid fuel,’’ ‘‘Load fraction,’’
‘‘Metal process furnaces,’’ ‘‘Minimum
activated carbon injection rate,’’
‘‘Minimum scrubber liquid flow rate,’’
‘‘Minimum sorbent injection rate,’’
‘‘Natural gas,’’ ‘‘Other gas 1 fuel,’’
‘‘Period of natural gas curtailment or
supply interruption,’’ ‘‘Process heater,’’
‘‘Qualified energy assessor,’’ ‘‘Residual
oil,’’ ‘‘Solid fossil fuel,’’ ‘‘Steam
output,’’ ‘‘Stoker,’’ ‘‘Temporary boiler,’’
‘‘Tune-up,’’ ‘‘Unit designed to burn gas
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1 subcategory,’’ ‘‘Unit designed to burn
gas 2 (other) subcategory,’’ ‘‘Unit
designed to burn liquid subcategory,’’
‘‘Unit designed to burn liquid fuel that
is a non-continental unit,’’ ‘‘Unit
designed to burn solid fuel,’’ ‘‘Waste
heat boiler,’’ ‘‘Waste heat process
heater.’’
■ c. Removing the definitions for
‘‘Benchmarking,’’ ‘‘Emission credit,’’
‘‘Liquid fuel subcategory,’’ and
‘‘Suspension boiler.’’
The revisions read as follows:
§ 63.7575
subpart?
What definitions apply to this
*
*
*
*
*
10-day rolling average means the
arithmetic mean of the previous 240
hours of valid operating data. Valid data
excludes hours during startup and
shutdown, data collected during periods
when the monitoring system is out of
control as specified in your site-specific
monitoring plan, while conducting
repairs associated with periods when
the monitoring system is out of control,
or while conducting required
monitoring system quality assurance or
quality control activities, and periods
when this unit is not operating. The 240
hours should be consecutive, but not
necessarily continuous if operations
were intermittent.
30-day rolling average means the
arithmetic mean of the previous 720
hours of valid operating data. Valid data
excludes hours during startup and
shutdown, data collected during periods
when the monitoring system is out of
control as specified in your site-specific
monitoring plan, while conducting
repairs associated with periods when
the monitoring system is out of control,
or while conducting required
monitoring system quality assurance or
quality control activities, and periods
when this unit is not operating. The 720
hours should be consecutive, but not
necessarily continuous if operations
were intermittent.
*
*
*
*
*
Annual capacity factor means the
ratio between the actual heat input to a
boiler or process heater from the fuels
burned during a calendar year and the
potential heat input to the boiler or
process heater had it been operated for
8,760 hours during a year at the
maximum steady state design heat input
capacity.
Average annual heat input rate means
total heat input divided by the hours of
operation for the 12 months preceding
the compliance demonstration.
*
*
*
*
*
Benchmark means the fuel heat input
for a boiler or process heater for the oneyear period before the date that an
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energy demand reduction occurs, unless
it can be demonstrated that a different
time period is more representative of
historical operations.
Biodiesel means a mono-alkyl ester
derived from biomass and conforming to
ASTM D6751–11b, Standard
Specification for Biodiesel Fuel Blend
Stock (B100) for Middle Distillate Fuels
(incorporated by reference, see § 63.14).
*
*
*
*
*
Boiler means an enclosed device
using controlled flame combustion and
having the primary purpose of
recovering thermal energy in the form of
steam or hot water. Controlled flame
combustion refers to a steady-state, or
near steady-state, process wherein fuel
and/or oxidizer feed rates are
controlled. A device combusting solid
waste, as defined in § 241.3 of this
chapter, is not a boiler unless the device
is exempt from the definition of a solid
waste incineration unit as provided in
section 129(g)(1) of the Clean Air Act.
Waste heat boilers are excluded from
this definition.
Boiler system means the boiler and
associated components, such as, the
feed water system, the combustion air
system, the fuel system (including
burners), blowdown system, combustion
control systems, steam systems, and
condensate return systems.
*
*
*
*
*
Coal means all solid fuels classifiable
as anthracite, bituminous, subbituminous, or lignite by ASTM D388
(incorporated by reference, see § 63.14),
coal refuse, and petroleum coke. For the
purposes of this subpart, this definition
of ‘‘coal’’ includes synthetic fuels
derived from coal, including but not
limited to, solvent-refined coal, coal-oil
mixtures, and coal-water mixtures. Coal
derived gases are excluded from this
definition.
*
*
*
*
*
Commercial/institutional boiler
means a boiler used in commercial
establishments or institutional
establishments such as medical centers,
nursing homes, research centers,
institutions of higher education,
elementary and secondary schools,
libraries, religious establishments,
governmental buildings, hotels,
restaurants, and laundries to provide
electricity, steam, and/or hot water.
*
*
*
*
*
Daily block average means the
arithmetic mean of all valid emission
concentrations or parameter levels
recorded when a unit is operating
measured over the 24-hour period from
12 a.m. (midnight) to 12 a.m.
(midnight), except for periods of startup
and shutdown or downtime.
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Deviation.
(1) Deviation means any instance in
which an affected source subject to this
subpart, or an owner or operator of such
a source:
(i) Fails to meet any applicable
requirement or obligation established by
this subpart including, but not limited
to, any emission limit, operating limit,
or work practice standard; or
(ii) Fails to meet any term or
condition that is adopted to implement
an applicable requirement in this
subpart and that is included in the
operating permit for any affected source
required to obtain such a permit.
(2) A deviation is not always a
violation.
*
*
*
*
*
Distillate oil means fuel oils that
contain 0.05 weight percent nitrogen or
less and comply with the specifications
for fuel oil numbers 1 and 2, as defined
by the American Society of Testing and
Materials in ASTM D396 (incorporated
by reference, see § 63.14) or diesel fuel
oil numbers 1 and 2, as defined by the
American Society for Testing and
Materials in ASTM D975 (incorporated
by reference, see § 63.14), kerosene, and
biodiesel as defined by the American
Society of Testing and Materials in
ASTM D6751–11b (incorporated by
reference, see § 60.14).
Dry scrubber means an add-on air
pollution control system that injects dry
alkaline sorbent (dry injection) or sprays
an alkaline sorbent (spray dryer) to react
with and neutralize acid gas in the
exhaust stream forming a dry powder
material. Sorbent injection systems used
as control devices in fluidized bed
boilers and process heaters are included
in this definition. A dry scrubber is a
dry control system.
Dutch oven means a unit having a
refractory-walled cell connected to a
conventional boiler setting. Fuel
materials are introduced through an
opening in the roof of the dutch oven
and burn in a pile on its floor. Fluidized
bed boilers are not part of the dutch
oven design category.
Electric utility steam generating unit
(EGU) means a fossil fuel-fired
combustion unit of more than 25
megawatts electric (MWe) that serves a
generator that produces electricity for
sale. A fossil fuel-fired unit that
cogenerates steam and electricity and
supplies more than one-third of its
potential electric output capacity and
more than 25 MWe output to any utility
power distribution system for sale is
considered an electric utility steam
generating unit. To be ‘‘capable of
combusting’’ fossil fuels, an EGU would
need to have these fuels allowed in their
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operating permits and have the
appropriate fuel handling facilities onsite or otherwise available (e.g., coal
handling equipment, including coal
storage area, belts and conveyers,
pulverizers, etc.; oil storage facilities). In
addition, fossil fuel-fired EGU means
any EGU that fired fossil fuel for more
than 10.0 percent of the average annual
heat input in any 3 consecutive calendar
years or for more than 15.0 percent of
the annual heat input during any one
calendar year after April 16, 2012.
*
*
*
*
*
Efficiency credit means emission
reductions above those required by this
subpart. Efficiency credits generated
may be used to comply with the
emissions limits. Credits may come
from pollution prevention projects that
result in reduced fuel use by affected
units. Boilers that are shut down cannot
be used to generate credits unless the
facility provides documentation linking
the permanent shutdown to
implementation of the energy
conservation measures identified in the
energy assessment.
Energy assessment means the
following for the emission units covered
by this subpart:
(1) The energy assessment for
facilities with affected boilers and
process heaters with a combined heat
input capacity of less than 0.3 trillion
Btu (TBtu) per year will be 8 on-site
technical labor hours in length
maximum, but may be longer at the
discretion of the owner or operator of
the affected source. The boiler system(s)
and any on-site energy use system(s)
accounting for at least 50 percent of the
affected boiler(s) energy (e.g., steam, hot
water, process heat, or electricity)
production, as applicable, will be
evaluated to identify energy savings
opportunities, within the limit of
performing an 8-hour on-site energy
assessment.
(2) The energy assessment for
facilities with affected boilers and
process heaters with a combined heat
input capacity of 0.3 to 1.0 TBtu/year
will be 24 on-site technical labor hours
in length maximum, but may be longer
at the discretion of the owner or
operator of the affected source. The
boiler system(s) and any on-site energy
use system(s) accounting for at least 33
percent of the energy (e.g., steam, hot
water, process heat, or electricity)
production, as applicable, will be
evaluated to identify energy savings
opportunities, within the limit of
performing a 24-hour on-site energy
assessment.
(3) The energy assessment for
facilities with affected boilers and
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process heaters with a combined heat
input capacity greater than 1.0 TBtu/
year will be up to 24 on-site technical
labor hours in length for the first TBtu/
yr plus 8 on-site technical labor hours
for every additional 1.0 TBtu/yr not to
exceed 160 on-site technical hours, but
may be longer at the discretion of the
owner or operator of the affected source.
The boiler system(s), process heater(s),
and any on-site energy use system(s)
accounting for at least 20 percent of the
energy (e.g., steam, process heat, hot
water, or electricity) production, as
applicable, will be evaluated to identify
energy savings opportunities.
(4) The on-site energy use systems
serving as the basis for the percent of
affected boiler(s) and process heater(s)
energy production in paragraphs (1), (2),
and (3) of this definition may be
segmented by production area or energy
use area as most logical and applicable
to the specific facility being assessed
(e.g., product X manufacturing area;
product Y drying area; Building Z).
*
*
*
*
*
Energy management program means a
program that includes a set of practices
and procedures designed to manage
energy use that are demonstrated by the
facility’s energy policies, a facility
energy manager and other staffing
responsibilities, energy performance
measurement and tracking methods, an
energy saving goal, action plans,
operating procedures, internal reporting
requirements, and periodic review
intervals used at the facility. Facilities
may establish their program through
energy management systems compatible
with ISO 50001.
Energy use system includes the
following systems located on-site that
use energy (steam, hot water, or
electricity) provided by the affected
boiler or process heater: process heating;
compressed air systems; machine drive
(motors, pumps, fans); process cooling;
facility heating, ventilation, and airconditioning systems; hot water
systems; building envelop; and lighting;
or other systems that use steam, hot
water, process heat, or electricity
provided by the affected boiler or
process heater. Energy use systems are
only those systems using energy clearly
produced by affected boilers and
process heaters.
Equivalent means the following only
as this term is used in Table 6 to this
subpart:
(1) An equivalent sample collection
procedure means a published voluntary
consensus standard or practice (VCS) or
EPA method that includes collection of
a minimum of three composite fuel
samples, with each composite
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consisting of a minimum of three
increments collected at approximately
equal intervals over the test period.
(2) An equivalent sample compositing
procedure means a published VCS or
EPA method to systematically mix and
obtain a representative subsample (part)
of the composite sample.
(3) An equivalent sample preparation
procedure means a published VCS or
EPA method that: Clearly states that the
standard, practice or method is
appropriate for the pollutant and the
fuel matrix; or is cited as an appropriate
sample preparation standard, practice or
method for the pollutant in the chosen
VCS or EPA determinative or analytical
method.
(4) An equivalent procedure for
determining heat content means a
published VCS or EPA method to obtain
gross calorific (or higher heating) value.
(5) An equivalent procedure for
determining fuel moisture content
means a published VCS or EPA method
to obtain moisture content. If the sample
analysis plan calls for determining
metals (especially the mercury,
selenium, or arsenic) using an aliquot of
the dried sample, then the drying
temperature must be modified to
prevent vaporizing these metals. On the
other hand, if metals analysis is done on
an ‘‘as received’’ basis, a separate
aliquot can be dried to determine
moisture content and the metals
concentration mathematically adjusted
to a dry basis.
(6) An equivalent pollutant (mercury,
HCl) determinative or analytical
procedure means a published VCS or
EPA method that clearly states that the
standard, practice, or method is
appropriate for the pollutant and the
fuel matrix and has a published
detection limit equal or lower than the
methods listed in Table 6 to this subpart
for the same purpose.
*
*
*
*
*
Federally enforceable means all
limitations and conditions that are
enforceable by the EPA Administrator,
including, but not limited to, the
requirements of 40 CFR parts 60, 61, 63,
and 65, requirements within any
applicable state implementation plan,
and any permit requirements
established under 40 CFR 52.21 or
under 40 CFR 51.18 and 40 CFR 51.24.
Fluidized bed boiler means a boiler
utilizing a fluidized bed combustion
process that is not a pulverized coal
boiler.
Fluidized bed boiler with an
integrated fluidized bed heat exchanger
means a boiler utilizing a fluidized bed
combustion where the entire tube
surface area is located outside of the
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furnace section at the exit of the cyclone
section and exposed to the flue gas
stream for conductive heat transfer. This
design applies only to boilers in the unit
designed to burn coal/solid fossil fuel
subcategory that fire coal refuse.
*
*
*
*
*
Fuel cell means a boiler type in which
the fuel is dropped onto suspended
fixed grates and is fired in a pile. The
refractory-lined fuel cell uses
combustion air preheating and
positioning of secondary and tertiary air
injection ports to improve boiler
efficiency. Fluidized bed, dutch oven,
pile burner, hybrid suspension grate,
and suspension burners are not part of
the fuel cell subcategory.
Fuel type means each category of fuels
that share a common name or
classification. Examples include, but are
not limited to, bituminous coal, subbituminous coal, lignite, anthracite,
biomass, distillate oil, residual oil.
Individual fuel types received from
different suppliers are not considered
new fuel types.
Gaseous fuel includes, but is not
limited to, natural gas, process gas,
landfill gas, coal derived gas, refinery
gas, and biogas. Blast furnace gas and
process gases that are regulated under
another subpart of this part, or part 60,
part 61, or part 65 of this chapter, are
exempted from this definition.
Heat input means heat derived from
combustion of fuel in a boiler or process
heater and does not include the heat
input from preheated combustion air,
recirculated flue gases, returned
condensate, or exhaust gases from other
sources such as gas turbines, internal
combustion engines, kilns, etc.
Heavy liquid includes residual oil and
any other liquid fuel not classified as a
light liquid.
*
*
*
*
*
Hot water heater means a closed
vessel with a capacity of no more than
120 U.S. gallons in which water is
heated by combustion of gaseous,
liquid, or biomass/bio-based solid fuel
and is withdrawn for use external to the
vessel. Hot water boilers (i.e., not
generating steam) combusting gaseous,
liquid, or biomass fuel with a heat input
capacity of less than 1.6 million Btu per
hour are included in this definition. The
120 U.S. gallon capacity threshold to be
considered a hot water heater is
independent of the 1.6 MMBtu/hr heat
input capacity threshold for hot water
boilers. Hot water heater also means a
tankless unit that provides on demand
hot water.
Hybrid suspension grate boiler means
a boiler designed with air distributors to
spread the fuel material over the entire
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width and depth of the boiler
combustion zone. The biomass fuel
combusted in these units exceeds a
moisture content of 40 percent on an asfired annual heat input basis. The
drying and much of the combustion of
the fuel takes place in suspension, and
the combustion is completed on the
grate or floor of the boiler. Fluidized
bed, dutch oven, and pile burner
designs are not part of the hybrid
suspension grate boiler design category.
Industrial boiler means a boiler used
in manufacturing, processing, mining,
and refining or any other industry to
provide steam, hot water, and/or
electricity.
Light liquid includes distillate oil,
biodiesel, or vegetable oil.
Limited-use boiler or process heater
means any boiler or process heater that
burns any amount of solid, liquid, or
gaseous fuels and has a federally
enforceable average annual capacity
factor of no more than 10 percent.
Liquid fuel includes, but is not
limited to, light liquid, heavy liquid,
any form of liquid fuel derived from
petroleum, used oil, liquid biofuels,
biodiesel, vegetable oil, and comparable
fuels as defined under 40 CFR 261.38.
Load fraction means the actual heat
input of a boiler or process heater
divided by heat input during the
performance test that established the
minimum sorbent injection rate or
minimum activated carbon injection
rate, expressed as a fraction (e.g., for 50
percent load the load fraction is 0.5).
Major source for oil and natural gas
production facilities, as used in this
subpart, shall have the same meaning as
in § 63.2, except that:
(1) Emissions from any oil or gas
exploration or production well (with its
associated equipment, as defined in this
section), and emissions from any
pipeline compressor station or pump
station shall not be aggregated with
emissions from other similar units to
determine whether such emission
points or stations are major sources,
even when emission points are in a
contiguous area or under common
control;
(2) Emissions from processes,
operations, or equipment that are not
part of the same facility, as defined in
this section, shall not be aggregated; and
(3) For facilities that are production
field facilities, only HAP emissions from
glycol dehydration units and storage
vessels with the potential for flash
emissions shall be aggregated for a
major source determination. For
facilities that are not production field
facilities, HAP emissions from all HAP
emission units shall be aggregated for a
major source determination.
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Metal process furnaces are a
subcategory of process heaters, as
defined in this subpart, which include
natural gas-fired annealing furnaces,
preheat furnaces, reheat furnaces, aging
furnaces, heat treat furnaces, and
homogenizing furnaces.
*
*
*
*
*
Minimum activated carbon injection
rate means load fraction multiplied by
the lowest hourly average activated
carbon injection rate measured
according to Table 7 to this subpart
during the most recent performance test
demonstrating compliance with the
applicable emission limit.
Minimum oxygen level means the
lowest hourly average oxygen level
measured according to Table 7 to this
subpart during the most recent
performance test demonstrating
compliance with the applicable
emission limit.
*
*
*
*
*
Minimum scrubber liquid flow rate
means the lowest hourly average liquid
flow rate (e.g., to the PM scrubber or to
the acid gas scrubber) measured
according to Table 7 to this subpart
during the most recent performance
stack test demonstrating compliance
with the applicable emission limit.
*
*
*
*
*
Minimum sorbent injection rate
means:
(1) The load fraction multiplied by the
lowest hourly average sorbent injection
rate for each sorbent measured
according to Table 7 to this subpart
during the most recent performance test
demonstrating compliance with the
applicable emission limits; or
(2) For fluidized bed combustion, the
lowest average ratio of sorbent to sulfur
measured during the most recent
performance test.
*
*
*
*
*
Natural gas means:
(1) A naturally occurring mixture of
hydrocarbon and nonhydrocarbon gases
found in geologic formations beneath
the earth’s surface, of which the
principal constituent is methane; or
(2) Liquefied petroleum gas, as
defined in ASTM D1835 (incorporated
by reference, see § 63.14); or
(3) A mixture of hydrocarbons that
maintains a gaseous state at ISO
conditions. Additionally, natural gas
must either be composed of at least 70
percent methane by volume or have a
gross calorific value between 35 and 41
megajoules (MJ) per dry standard cubic
meter (950 and 1,100 Btu per dry
standard cubic foot); or
(4) Propane or propane derived
synthetic natural gas. Propane means a
colorless gas derived from petroleum
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and natural gas, with the molecular
structure C3H8.
*
*
*
*
*
Other combustor means a unit
designed to burn solid fuel that is not
classified as a dutch oven, fluidized
bed, fuel cell, hybrid suspension grate
boiler, pulverized coal boiler, stoker,
sloped grate, or suspension boiler as
defined in this subpart.
Other gas 1 fuel means a gaseous fuel
that is not natural gas or refinery gas
and does not exceed a maximum
concentration of 40 micrograms/cubic
meters of mercury.
Oxygen analyzer system means all
equipment required to determine the
oxygen content of a gas stream and used
to monitor oxygen in the boiler or
process heater flue gas, boiler or process
heater, firebox, or other appropriate
location. This definition includes
oxygen trim systems. The source owner
or operator must install, calibrate,
maintain, and operate the oxygen
analyzer system in accordance with the
manufacturer’s recommendations.
Oxygen trim system means a system of
monitors that is used to maintain excess
air at the desired level in a combustion
device. A typical system consists of a
flue gas oxygen and/or CO monitor that
automatically provides a feedback signal
to the combustion air controller.
*
*
*
*
*
Period of gas curtailment or supply
interruption means a period of time
during which the supply of gaseous fuel
to an affected boiler or process heater is
restricted or halted for reasons beyond
the control of the facility. The act of
entering into a contractual agreement
with a supplier of natural gas
established for curtailment purposes
does not constitute a reason that is
under the control of a facility for the
purposes of this definition. An increase
in the cost or unit price of natural gas
due to normal market fluctuations not
during periods of supplier delivery
restriction does not constitute a period
of natural gas curtailment or supply
interruption. On-site gaseous fuel
system emergencies or equipment
failures qualify as periods of supply
interruption when the emergency or
failure is beyond the control of the
facility.
Pile burner means a boiler design
incorporating a design where the
anticipated biomass fuel has a high
relative moisture content. Grates serve
to support the fuel, and underfire air
flowing up through the grates provides
oxygen for combustion, cools the grates,
promotes turbulence in the fuel bed,
and fires the fuel. The most common
form of pile burning is the dutch oven.
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Process heater means an enclosed
device using controlled flame, and the
unit’s primary purpose is to transfer
heat indirectly to a process material
(liquid, gas, or solid) or to a heat transfer
material (e.g., glycol or a mixture of
glycol and water) for use in a process
unit, instead of generating steam.
Process heaters are devices in which the
combustion gases do not come into
direct contact with process materials. A
device combusting solid waste, as
defined in § 241.3 of this chapter, is not
a process heater unless the device is
exempt from the definition of a solid
waste incineration unit as provided in
section 129(g)(1) of the Clean Air Act.
Process heaters do not include units
used for comfort heat or space heat, food
preparation for on-site consumption, or
autoclaves. Waste heat process heaters
are excluded from this definition.
*
*
*
*
*
Qualified energy assessor means:
(1) Someone who has demonstrated
capabilities to evaluate energy savings
opportunities for steam generation and
major energy using systems, including,
but not limited to:
(i) Boiler combustion management.
(ii) Boiler thermal energy recovery,
including
(A) Conventional feed water
economizer,
(B) Conventional combustion air
preheater, and
(C) Condensing economizer.
(iii) Boiler blowdown thermal energy
recovery.
(iv) Primary energy resource selection,
including
(A) Fuel (primary energy source)
switching, and
(B) Applied steam energy versus
direct-fired energy versus electricity.
(v) Insulation issues.
(vi) Steam trap and steam leak
management.
(vi) Condensate recovery.
(viii) Steam end-use management.
(2) Capabilities and knowledge
includes, but is not limited to:
(i) Background, experience, and
recognized abilities to perform the
assessment activities, data analysis, and
report preparation.
(ii) Familiarity with operating and
maintenance practices for steam or
process heating systems.
(iii) Additional potential steam
system improvement opportunities
including improving steam turbine
operations and reducing steam demand.
(iv) Additional process heating system
opportunities including effective
utilization of waste heat and use of
proper process heating methods.
(v) Boiler-steam turbine cogeneration
systems.
E:\FR\FM\31JAR3.SGM
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Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
7191
(ii) For PM and CO emission limits for
boilers in one of the subcategories of
units designed to burn coal use
Equation 22 of this section:
Where:
ELOBE = Emission limit in units of pounds
per megawatt-hour.
ELT = Appropriate emission limit from Table
1 or 2 of this subpart in units of pounds
per million Btu heat input.
(iii) For PM and CO emission limits
for boilers in one of the subcategories of
units designed to burn biomass use
Equation 23 of this section:
Where:
ELOBE = Emission limit in units of pounds
per megawatt-hour.
ELT = Appropriate emission limit from Table
1 or 2 of this subpart in units of pounds
per million Btu heat input.
(iv) For emission limits for boilers in
one of the subcategories of units
designed to burn liquid fuels use
Equation 24 of this section:
Where:
ELOBE = Emission limit in units of pounds
per megawatt-hour.
ELT = Appropriate emission limit from Table
1 or 2 of this subpart in units of pounds
per million Btu heat input.
(v) For emission limits for boilers in
the unit designed to burn gas 2 (other)
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E:\FR\FM\31JAR3.SGM
31JAR3
ER31JA13.026</GPH> ER31JA13.027</GPH>
ELT = Appropriate emission limit from Table
1 or 2 of this subpart in units of pounds
per million Btu heat input.
ER31JA13.028</GPH>
heater for the purpose of supplying
steam or heat for heating and/or
producing electricity, or for any other
purpose, or the firing of fuel in a boiler
after a shutdown event for any purpose.
Startup ends when any of the steam or
heat from the boiler or process heater is
supplied for heating, and/or producing
electricity, or for any other purpose.
Steam output means:
(1) For a boiler that produces steam
for process or heating only (no power
generation), the energy content in terms
of MMBtu of the boiler steam output,
(2) For a boiler that cogenerates
process steam and electricity (also
known as combined heat and power),
the total energy output, which is the
sum of the energy content of the steam
exiting the turbine and sent to process
in MMBtu and the energy of the
electricity generated converted to
MMBtu at a rate of 10,000 Btu per
kilowatt-hour generated (10 MMBtu per
megawatt-hour), and
(3) For a boiler that generates only
electricity, the alternate output-based
emission limits would be calculated
using Equations 21 through 25 of this
section, as appropriate:
(i) For emission limits for boilers in
the unit designed to burn solid fuel
subcategory use Equation 21 of this
section:
ER31JA13.025</GPH>
ASTM D396–10 (incorporated by
reference, see § 63.14(b)).
*
*
*
*
*
Secondary material means the
material as defined in § 241.2 of this
chapter.
Shutdown means the cessation of
operation of a boiler or process heater
for any purpose. Shutdown begins
either when none of the steam from the
boiler is supplied for heating and/or
producing electricity, or for any other
purpose, or at the point of no fuel being
fired in the boiler or process heater,
whichever is earlier. Shutdown ends
when there is no steam and no heat
being supplied and no fuel being fired
in the boiler or process heater.
Sloped grate means a unit where the
solid fuel is fed to the top of the grate
from where it slides downwards; while
sliding the fuel first dries and then
ignites and burns. The ash is deposited
at the bottom of the grate. Fluidized bed,
dutch oven, pile burner, hybrid
suspension grate, suspension burners,
and fuel cells are not considered to be
a sloped grate design.
Solid fossil fuel includes, but is not
limited to, coal, coke, petroleum coke,
and tire derived fuel.
*
*
*
*
*
Startup means either the first-ever
firing of fuel in a boiler or process
Where:
ELOBE = Emission limit in units of pounds
per megawatt-hour.
tkelley on DSK3SPTVN1PROD with
(vi) Industry specific steam end-use
systems.
*
*
*
*
*
Regulated gas stream means an offgas
stream that is routed to a boiler or
process heater for the purpose of
achieving compliance with a standard
under another subpart of this part or
part 60, part 61, or part 65 of this
chapter.
Residential boiler means a boiler used
to provide heat and/or hot water and/or
as part of a residential combined heat
and power system. This definition
includes boilers located at an
institutional facility (e.g., university
campus, military base, church grounds)
or commercial/industrial facility (e.g.,
farm) used primarily to provide heat
and/or hot water for:
(1) A dwelling containing four or
fewer families; or
(2) A single unit residence dwelling
that has since been converted or
subdivided into condominiums or
apartments.
Residual oil means crude oil, fuel oil
that does not comply with the
specifications under the definition of
distillate oil, and all fuel oil numbers 4,
5, and 6, as defined by the American
Society of Testing and Materials in
7192
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
tkelley on DSK3SPTVN1PROD with
Where:
ELOBE = Emission limit in units of pounds
per megawatt-hour.
ELT = Appropriate emission limit from Table
1 or 2 of this subpart in units of pounds
per million Btu heat input.
Stoker means a unit consisting of a
mechanically operated fuel feeding
mechanism, a stationary or moving grate
to support the burning of fuel and admit
under-grate air to the fuel, an overfire
air system to complete combustion, and
an ash discharge system. This definition
of stoker includes air swept stokers.
There are two general types of stokers:
Underfeed and overfeed. Overfeed
stokers include mass feed and spreader
stokers. Fluidized bed, dutch oven, pile
burner, hybrid suspension grate,
suspension burners, and fuel cells are
not considered to be a stoker design.
Stoker/sloped grate/other unit
designed to burn kiln dried biomass
means the unit is in the units designed
to burn biomass/bio-based solid
subcategory that is either a stoker,
sloped grate, or other combustor design
and is not in the stoker/sloped grate/
other units designed to burn wet
biomass subcategory.
Stoker/sloped grate/other unit
designed to burn wet biomass means the
unit is in the units designed to burn
biomass/bio-based solid subcategory
that is either a stoker, sloped grate, or
other combustor design and any of the
biomass/bio-based solid fuel combusted
in the unit exceeds 20 percent moisture
on an annual heat input basis.
Suspension burner means a unit
designed to fire dry biomass/biobased
solid particles in suspension that are
conveyed in an airstream to the furnace
like pulverized coal. The combustion of
the fuel material is completed on a grate
or floor below. The biomass/biobased
fuel combusted in the unit shall not
exceed 20 percent moisture on an
annual heat input basis. Fluidized bed,
dutch oven, pile burner, and hybrid
suspension grate units are not part of
the suspension burner subcategory.
Temporary boiler means any gaseous
or liquid fuel boiler that is designed to,
and is capable of, being carried or
moved from one location to another by
means of, for example, wheels, skids,
carrying handles, dollies, trailers, or
platforms. A boiler is not a temporary
boiler if any one of the following
conditions exists:
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(1) The equipment is attached to a
foundation.
(2) The boiler or a replacement
remains at a location within the facility
and performs the same or similar
function for more than 12 consecutive
months, unless the regulatory agency
approves an extension. An extension
may be granted by the regulating agency
upon petition by the owner or operator
of a unit specifying the basis for such a
request. Any temporary boiler that
replaces a temporary boiler at a location
and performs the same or similar
function will be included in calculating
the consecutive time period.
(3) The equipment is located at a
seasonal facility and operates during the
full annual operating period of the
seasonal facility, remains at the facility
for at least 2 years, and operates at that
facility for at least 3 months each year.
(4) The equipment is moved from one
location to another within the facility
but continues to perform the same or
similar function and serve the same
electricity, steam, and/or hot water
system in an attempt to circumvent the
residence time requirements of this
definition.
Total selected metals (TSM) means
the sum of the following metallic
hazardous air pollutants: arsenic,
beryllium, cadmium, chromium, lead,
manganese, nickel and selenium.
Traditional fuel means the fuel as
defined in § 241.2 of this chapter.
Tune-up means adjustments made to
a boiler or process heater in accordance
with the procedures outlined in
§ 63.7540(a)(10).
*
*
*
*
*
Ultra low sulfur liquid fuel means a
distillate oil that has less than or equal
to 15 ppm sulfur.
*
*
*
*
*
Unit designed to burn gas 1
subcategory includes any boiler or
process heater that burns only natural
gas, refinery gas, and/or other gas 1
fuels. Gaseous fuel boilers and process
heaters that burn liquid fuel for periodic
testing of liquid fuel, maintenance, or
operator training, not to exceed a
combined total of 48 hours during any
calendar year, are included in this
definition. Gaseous fuel boilers and
process heaters that burn liquid fuel
during periods of gas curtailment or gas
supply interruptions of any duration are
also included in this definition.
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Unit designed to burn gas 2 (other)
subcategory includes any boiler or
process heater that is not in the unit
designed to burn gas 1 subcategory and
burns any gaseous fuels either alone or
in combination with less than 10
percent coal/solid fossil fuel, and less
than 10 percent biomass/bio-based solid
fuel on an annual heat input basis, and
no liquid fuels. Gaseous fuel boilers and
process heaters that are not in the unit
designed to burn gas 1 subcategory and
that burn liquid fuel for periodic testing
of liquid fuel, maintenance, or operator
training, not to exceed a combined total
of 48 hours during any calendar year,
are included in this definition. Gaseous
fuel boilers and process heaters that are
not in the unit designed to burn gas 1
subcategory and that burn liquid fuel
during periods of gas curtailment or gas
supply interruption of any duration are
also included in this definition.
Unit designed to burn heavy liquid
subcategory means a unit in the unit
designed to burn liquid subcategory
where at least 10 percent of the heat
input from liquid fuels on an annual
heat input basis comes from heavy
liquids.
Unit designed to burn light liquid
subcategory means a unit in the unit
designed to burn liquid subcategory that
is not part of the unit designed to burn
heavy liquid subcategory.
Unit designed to burn liquid
subcategory includes any boiler or
process heater that burns any liquid
fuel, but less than 10 percent coal/solid
fossil fuel and less than 10 percent
biomass/bio-based solid fuel on an
annual heat input basis, either alone or
in combination with gaseous fuels.
Units in the unit design to burn gas 1
or unit designed to burn gas 2 (other)
subcategories that burn liquid fuel for
periodic testing of liquid fuel,
maintenance, or operator training, not to
exceed a combined total of 48 hours
during any calendar year are not
included in this definition. Units in the
unit design to burn gas 1 or unit
designed to burn gas 2 (other)
subcategories during periods of gas
curtailment or gas supply interruption
of any duration are also not included in
this definition.
Unit designed to burn liquid fuel that
is a non-continental unit means an
industrial, commercial, or institutional
boiler or process heater meeting the
definition of the unit designed to burn
E:\FR\FM\31JAR3.SGM
31JAR3
ER31JA13.029</GPH>
subcategory, use Equation 25 of this
section:
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
liquid subcategory located in the State
of Hawaii, the Virgin Islands, Guam,
American Samoa, the Commonwealth of
Puerto Rico, or the Northern Mariana
Islands.
Unit designed to burn solid fuel
subcategory means any boiler or process
heater that burns only solid fuels or at
least 10 percent solid fuel on an annual
heat input basis in combination with
liquid fuels or gaseous fuels.
Vegetable oil means oils extracted
from vegetation.
*
*
*
*
*
Waste heat boiler means a device that
recovers normally unused energy (i.e.,
hot exhaust gas) and converts it to
usable heat. Waste heat boilers are also
referred to as heat recovery steam
generators. Waste heat boilers are heat
exchangers generating steam from
incoming hot exhaust gas from an
industrial (e.g., thermal oxidizer, kiln,
furnace) or power (e.g., combustion
turbine, engine) equipment. Duct
burners are sometimes used to increase
the temperature of the incoming hot
exhaust gas.
7193
Waste heat process heater means an
enclosed device that recovers normally
unused energy (i.e., hot exhaust gas) and
converts it to usable heat. Waste heat
process heaters are also referred to as
recuperative process heaters. This
definition includes both fired and
unfired waste heat process heaters.
*
*
*
*
*
■ 28. Table 1 to subpart DDDDD of part
63 is revised to read as follows:
As stated in § 63.7500, you must
comply with the following applicable
emission limits:
TABLE 1 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS
HEATERS
[Units with heat input capacity of 10 million Btu per hour or greater]
The emissions must not exceed the following emission
limits, except during startup
and shutdown . . .
Or the emissions must not
exceed the following alternative output-based limits, except during startup and shutdown . . .
a. HCl .......................................
2.2E–02 lb per MMBtu of heat
input.
2.5E–02 lb per MMBtu of
steam output or 0.28 lb per
MWh.
b. Mercury ................................
8.0E–07 a lb per MMBtu of
heat input.
8.7E–07 a lb per MMBtu of
steam output or 1.1E–05 a lb
per MWh.
2. Units designed to burn coal/
solid fossil fuel.
a. Filterable PM (or TSM) ........
1.1E–03 lb per MMBtu of heat
input; or (2.3E–05 lb per
MMBtu of heat input).
3. Pulverized coal boilers designed to burn coal/solid fossil fuel.
a. Carbon monoxide (CO) (or
CEMS).
4. Stokers designed to burn
coal/solid fossil fuel.
a. CO (or CEMS) .....................
5. Fluidized bed units designed
to burn coal/solid fossil fuel.
a. CO (or CEMS) .....................
6. Fluidized bed units with an
integrated heat exchanger
designed to burn coal/solid
fossil fuel.
a. CO (or CEMS) .....................
7. Stokers/sloped grate/others
designed to burn wet biomass fuel.
a. CO (or CEMS) .....................
130 ppm by volume on a dry
basis corrected to 3 percent
oxygen, 3-run average; or
(320 ppm by volume on a
dry basis corrected to 3 percent oxygen, 30-day rolling
average).
130 ppm by volume on a dry
basis corrected to 3 percent
oxygen, 3-run average; or
(340 ppm by volume on a
dry basis corrected to 3 percent oxygen, 30-day rolling
average).
130 ppm by volume on a dry
basis corrected to 3 percent
oxygen, 3-run average; or
(230 ppm by volume on a
dry basis corrected to 3 percent oxygen, 30-day rolling
average).
140 ppm by volume on a dry
basis corrected to 3 percent
oxygen, 3-run average; or
(150 ppm by volume on a
dry basis corrected to 3 percent oxygen, 30-day rolling
average).
620 ppm by volume on a dry
basis corrected to 3 percent
oxygen, 3-run average; or
(390 ppm by volume on a
dry basis corrected to 3 percent oxygen, 30-day rolling
average).
3.0E–02 lb per MMBtu of heat
input; or (2.6E–05 lb per
MMBtu of heat input).
1.1E–03 lb per MMBtu of
steam output or 1.4E–02 lb
per MWh; or (2.7E–05 lb per
MMBtu of steam output or
2.9E–04 lb per MWh).
0.11 lb per MMBtu of steam
output or 1.4 lb per MWh; 3run average.
For the following
pollutants . . .
1. Units in all subcategories
designed to burn solid fuel.
tkelley on DSK3SPTVN1PROD with
If your boiler or process heater
is in this subcategory . . .
b. Filterable PM (or TSM) ........
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Using this specified sampling
volume or test run duration
. . .
For M26A, collect a minimum
of 1 dscm per run; for M26
collect a minimum of 120 liters per run.
For M29, collect a minimum of
4 dscm per run; for M30A or
M30B, collect a minimum
sample as specified in the
method; for ASTM D6784 b
collect a minimum of 4
dscm.
Collect a minimum of 3 dscm
per run.
1 hr minimum sampling time.
0.12 lb per MMBtu of steam
output or 1.4 lb per MWh; 3run average.
1 hr minimum sampling time.
0.11 lb per MMBtu of steam
output or 1.4 lb per MWh; 3run average.
1 hr minimum sampling time.
1.2E–01 lb per MMBtu of
steam output or 1.5 lb per
MWh; 3-run average.
1 hr minimum sampling time.
5.8E–01 lb per MMBtu of
steam output or 6.8 lb per
MWh; 3-run average.
1 hr minimum sampling time.
3.5E–02 lb per MMBtu of
steam output or 4.2E–01 lb
per MWh; or (2.7E–05 lb per
MMBtu of steam output or
3.7E–04 lb per MWh).
Collect a minimum of 2 dscm
per run.
E:\FR\FM\31JAR3.SGM
31JAR3
7194
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
TABLE 1 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS
HEATERS—Continued
[Units with heat input capacity of 10 million Btu per hour or greater]
The emissions must not exceed the following emission
limits, except during startup
and shutdown . . .
If your boiler or process heater
is in this subcategory . . .
For the following
pollutants . . .
8. Stokers/sloped grate/others
designed to burn kiln-dried
biomass fuel.
a. CO .......................................
b. Filterable PM (or TSM) ........
9. Fluidized bed units designed
to burn biomass/bio-based
solids.
a. CO (or CEMS) .....................
b. Filterable PM (or TSM) ........
10. Suspension burners designed to burn biomass/biobased solids.
a. CO (or CEMS) .....................
b. Filterable PM (or TSM) ........
11. Dutch Ovens/Pile burners
designed to burn biomass/
bio-based solids.
a. CO (or CEMS) .....................
b. Filterable PM (or TSM) ........
12. Fuel cell units designed to
burn biomass/bio-based solids.
a. CO .......................................
b. Filterable PM (or TSM) ........
13. Hybrid suspension grate
boiler designed to burn biomass/bio-based solids.
a. CO (or CEMS) .....................
b. Filterable PM (or TSM) ........
460 ppm by volume on a dry
basis corrected to 3 percent
oxygen.
3.0E–02 lb per MMBtu of heat
input; or (4.0E–03 lb per
MMBtu of heat input).
4.2E–01 lb per MMBtu of
steam output or 5.1 lb per
MWh.
3.5E–02 lb per MMBtu of
steam output or 4.2E–01 lb
per MWh; or (4.2E–03 lb per
MMBtu of steam output or
5.6E–02 lb per MWh).
2.2E–01 lb per MMBtu of
steam output or 2.6 lb per
MWh; 3-run average.
1 hr minimum sampling time.
1.2E–02 lb per MMBtu of
steam output or 0.14 lb per
MWh; or (1.1E–04 a lb per
MMBtu of steam output or
1.2E–03 a lb per MWh).
1.9 lb per MMBtu of steam output or 27 lb per MWh; 3-run
average.
Collect a minimum of 3 dscm
per run.
230 ppm by volume on a dry
basis corrected to 3 percent
oxygen, 3-run average; or
(310 ppm by volume on a
dry basis corrected to 3 percent oxygen, 30-day rolling
average).
9.8E–03 lb per MMBtu of heat
input; or (8.3E–05 a lb per
MMBtu of heat input).
2,400 ppm by volume on a dry
basis corrected to 3 percent
oxygen, 3-run average; or
(2,000 ppm by volume on a
dry basis corrected to 3 percent oxygen, 10-day rolling
average).
3.0E–02 lb per MMBtu of heat
input; or (6.5E–03 lb per
MMBtu of heat input).
330 ppm by volume on a dry
basis corrected to 3 percent
oxygen, 3-run average; or
(520 ppm by volume on a
dry basis corrected to 3 percent oxygen, 10-day rolling
average).
3.2E–03 lb per MMBtu of heat
input; or (3.9E–05 lb per
MMBtu of heat input).
910 ppm by volume on a dry
basis corrected to 3 percent
oxygen.
2.0E–02 lb per MMBtu of heat
input; or (2.9E–05 a lb per
MMBtu of heat input).
1,100 ppm by volume on a dry
basis corrected to 3 percent
oxygen, 3-run average; or
(900 ppm by volume on a
dry basis corrected to 3 percent oxygen, 30-day rolling
average).
2.6E–02 lb per MMBtu of heat
input; or (4.4E–04 lb per
MMBtu of heat input).
VerDate Mar<15>2010
a. HCl .......................................
4.4E–04 lb per MMBtu of heat
input.
b. Mercury ................................
tkelley on DSK3SPTVN1PROD with
14. Units designed to burn liquid fuel.
Or the emissions must not
exceed the following alternative output-based limits, except during startup and shutdown . . .
4.8E–07 a lb per MMBtu of
heat input.
18:47 Jan 30, 2013
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3.1E–02 lb per MMBtu of
steam output or 4.2E–01 lb
per MWh; or (6.6E–03 lb per
MMBtu of steam output or
9.1E–02 lb per MWh).
3.5E–01 lb per MMBtu of
steam output or 3.6 lb per
MWh; 3-run average.
4.3E–03 lb per MMBtu of
steam output or 4.5E–02 lb
per MWh; or (5.2E–05 lb per
MMBtu of steam output or
5.5E–04 lb per MWh).
1.1 lb per MMBtu of steam output or 1.0E+01 lb per MWh.
3.0E–02 lb per MMBtu of
steam output or 2.8E–01 lb
per MWh; or (5.1E–05 lb per
MMBtu of steam output or
4.1E–04 lb per MWh).
1.4 lb per MMBtu of steam output or 12 lb per MWh; 3-run
average.
3.3E–02 lb per MMBtu of
steam output or 3.7E–01 lb
per MWh; or (5.5E–04 lb per
MMBtu of steam output or
6.2E–03 lb per MWh).
4.8E–04 lb per MMBtu of
steam output or 6.1E–03 lb
per MWh.
5.3E–07 a lb per MMBtu of
steam output or 6.7E–06 a lb
per MWh.
E:\FR\FM\31JAR3.SGM
31JAR3
Using this specified sampling
volume or test run duration
. . .
Collect a minimum of 2 dscm
per run.
1 hr minimum sampling time.
1 hr minimum sampling time.
Collect a minimum of 2 dscm
per run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm
per run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm
per run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm
per run.
For M26A: Collect a minimum
of 2 dscm per run; for M26,
collect a minimum of 240 liters per run.
For M29, collect a minimum of
4 dscm per run; for M30A or
M30B, collect a minimum
sample as specified in the
method; for ASTM D6784 b
collect a minimum of 4
dscm.
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
7195
TABLE 1 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS AND PROCESS
HEATERS—Continued
[Units with heat input capacity of 10 million Btu per hour or greater]
The emissions must not exceed the following emission
limits, except during startup
and shutdown . . .
If your boiler or process heater
is in this subcategory . . .
For the following
pollutants . . .
15. Units designed to burn
heavy liquid fuel.
a. CO .......................................
b. Filterable PM (or TSM) ........
16. Units designed to burn light
liquid fuel.
a. CO .......................................
b. Filterable PM (or TSM) ........
17. Units designed to burn liquid fuel that are non-continental units.
a. CO .......................................
b. Filterable PM (or TSM) ........
18. Units designed to burn gas
2 (other) gases.
a. CO .......................................
b. HCl .......................................
Or the emissions must not
exceed the following alternative output-based limits, except during startup and shutdown . . .
130 ppm by volume on a dry
basis corrected to 3 percent
oxygen, 3-run average.
1.3E–02 lb per MMBtu of heat
input; or (7.5E–05 lb per
MMBtu of heat input).
0.13 lb per MMBtu of steam
output or 1.4 lb per MWh; 3run average.
1.5E–02 lb per MMBtu of
steam output or 1.8E–01 lb
per MWh; or (8.2E–05 lb per
MMBtu of steam output or
1.1E–03 lb per MWh).
0.13 lb per MMBtu of steam
output or 1.4 lb per MWh.
1 hr minimum sampling time.
1.2E–03 a lb per MMBtu of
steam output or 1.6E–02 a lb
per MWh; or (3.2E–05 lb per
MMBtu of steam output or
4.0E–04 lb per MWh).
0.13 lb per MMBtu of steam
output or 1.4 lb per MWh; 3run average.
Collect a minimum of 3 dscm
per run.
130 ppm by volume on a dry
basis corrected to 3 percent
oxygen.
1.1E–03 a lb per MMBtu of
heat input; or (2.9E–05 lb
per MMBtu of heat input).
130 ppm by volume on a dry
basis corrected to 3 percent
oxygen,
3-run
average
based on stack test.
2.3E–02 lb per MMBtu of heat
input; or (8.6E–04 lb per
MMBtu of heat input).
130 ppm by volume on a dry
basis corrected to 3 percent
oxygen.
1.7E–03 lb per MMBtu of heat
input.
2.5E–02 lb per MMBtu of
steam output or 3.2E–01 lb
per MWh; or (9.4E–04 lb per
MMBtu of steam output or
1.2E–02 lb per MWh).
0.16 lb per MMBtu of steam
output or 1.0 lb per MWh.
2.9E–03 lb per MMBtu of
steam output or 1.8E–02 lb
per MWh.
c. Mercury ................................
7.9E–06 lb per MMBtu of heat
input.
1.4E–05 lb per MMBtu of
steam output or 8.3E–05 lb
per MWh.
d. Filterable PM (or TSM) ........
6.7E–03 lb per MMBtu of heat
input; or (2.1E–04 lb per
MMBtu of heat input).
1.2E–02 lb per MMBtu of
steam output or 7.0E–02 lb
per MWh; or (3.5E–04 lb per
MMBtu of steam output or
2.2E–03 lb per MWh).
Using this specified sampling
volume or test run duration
. . .
Collect a minimum of 3 dscm
per run.
1 hr minimum sampling time.
1 hr minimum sampling time.
Collect a minimum of 4 dscm
per run.
1 hr minimum sampling time.
For M26A, Collect a minimum
of 2 dscm per run; for M26,
collect a minimum of 240 liters per run.
For M29, collect a minimum of
3 dscm per run; for M30A or
M30B, collect a minimum
sample as specified in the
method; for ASTM D6784 b
collect a minimum of 3
dscm.
Collect a minimum of 3 dscm
per run.
a If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant for at least 2 consecutive years show that your emissions are at or below this limit, you can skip testing according to § 63.7515 if all of the other provisions of § 63.7515 are met. For all other pollutants that do not contain a footnote ‘‘a’’, your performance tests for this pollutant for at least 2 consecutive years must show that your emissions are at or below 75 percent of this limit in
order to qualify for skip testing.
b Incorporated by reference, see § 63.14.
c If your affected source is a new or reconstructed affected source that commenced construction or reconstruction after June 4, 2010, and before January 31, 2013,
you may comply with the emission limits in Tables 11, 12 or 13 to this subpart until January 31, 2016. On and after January 31, 2016, you must comply with the
emission limits in Table 1 to this subpart.
29. Table 2 to subpart DDDDD of part
63 is revised to read as follows:
■
As stated in § 63.7500, you must
comply with the following applicable
emission limits:
TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS
[Units with heat input capacity of 10 million Btu per hour or greater]
The emissions must not exceed the following emission
limits, except during startup
and shutdown . . .
tkelley on DSK3SPTVN1PROD with
If your boiler or process heater
is in this subcategory . . .
For the following
pollutants . . .
1. Units in all subcategories
designed to burn solid fuel.
a. HCl .......................................
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The emissions must not exceed the following alternative
output-based limits, except
during startup and
shutdown . . .
2.2E–02 lb per MMBtu of heat
input.
2.5E–02 lb per MMBtu of
steam output or 0.27 lb per
MWh.
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Fmt 4701
Sfmt 4700
E:\FR\FM\31JAR3.SGM
31JAR3
Using this specified sampling
volume or test run
duration . . .
For M26A, Collect a minimum
of 1 dscm per run; for M26,
collect a minimum of 120 liters per run.
7196
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS—
Continued
[Units with heat input capacity of 10 million Btu per hour or greater]
The emissions must not exceed the following emission
limits, except during startup
and shutdown . . .
The emissions must not exceed the following alternative
output-based limits, except
during startup and
shutdown . . .
b. Mercury ................................
5.7E–06 lb per MMBtu of heat
input.
6.4E–06 lb per MMBtu of
steam output or 7.3E–05 lb
per MWh.
2. Units design to burn coal/
solid fossil fuel.
a. Filterable PM (or TSM) ........
4.0E–02 lb per MMBtu of heat
input; or (5.3E–05 lb per
MMBtu of heat input).
3. Pulverized coal boilers designed to burn coal/solid fossil fuel.
a. CO (or CEMS) .....................
4. Stokers designed to burn
coal/solid fossil fuel.
a. CO (or CEMS) .....................
5. Fluidized bed units designed
to burn coal/solid fossil fuel.
a. CO (or CEMS) .....................
6. Fluidized bed units with an
integrated heat exchanger
designed to burn coal/solid
fossil fuel.
a. CO (or CEMS) .....................
7. Stokers/sloped grate/others
designed to burn wet biomass fuel.
a. CO (or CEMS) .....................
130 ppm by volume on a dry
basis corrected to 3 percent
oxygen, 3-run average; or
(320 ppm by volume on a
dry basis corrected to 3 percent oxygen, 30-day rolling
average).
160 ppm by volume on a dry
basis corrected to 3 percent
oxygen, 3-run average; or
(340 ppm by volume on a
dry basis corrected to 3 percent oxygen, 30-day rolling
average).
130 ppm by volume on a dry
basis corrected to 3 percent
oxygen, 3-run average; or
(230 ppm by volume on a
dry basis corrected to 3 percent oxygen, 30-day rolling
average).
140 ppm by volume on a dry
basis corrected to 3 percent
oxygen, 3-run average; or
(150 ppm by volume on a
dry basis corrected to 3 percent oxygen, 30-day rolling
average).
1,500 ppm by volume on a dry
basis corrected to 3 percent
oxygen, 3-run average; or
(720 ppm by volume on a
dry basis corrected to 3 percent oxygen, 30-day rolling
average).
3.7E–02 lb per MMBtu of heat
input; or (2.4E–04 lb per
MMBtu of heat input).
4.2E–02 lb per MMBtu of
steam output or 4.9E–01 lb
per MWh; or (5.6E–05 lb per
MMBtu of steam output or
6.5E–04 lb per MWh).
0.11 lb per MMBtu of steam
output or 1.4 lb per MWh; 3run average.
If your boiler or process heater
is in this subcategory . . .
For the following
pollutants . . .
b. Filterable PM (or TSM) ........
8. Stokers/sloped grate/others
designed to burn kiln-dried
biomass fuel.
a. CO .......................................
b. Filterable PM (or TSM) ........
tkelley on DSK3SPTVN1PROD with
9. Fluidized bed units designed
to burn biomass/bio-based
solid.
a. CO (or CEMS) .....................
b. Filterable PM (or TSM) ........
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460 ppm by volume on a dry
basis corrected to 3 percent
oxygen.
3.2E–01 lb per MMBtu of heat
input; or (4.0E–03 lb per
MMBtu of heat input).
470 ppm by volume on a dry
basis corrected to 3 percent
oxygen, 3-run average; or
(310 ppm by volume on a
dry basis corrected to 3 percent oxygen, 30-day rolling
average).
1.1E–01 lb per MMBtu of heat
input; or (1.2E–03 lb per
MMBtu of heat input).
Frm 00060
Fmt 4701
Sfmt 4700
Using this specified sampling
volume or test run
duration . . .
For M29, collect a minimum of
3 dscm per run; for M30A or
M30B, collect a minimum
sample as specified in the
method; for ASTM D6784 b
collect a minimum of 3
dscm.
Collect a minimum of 2 dscm
per run.
1 hr minimum sampling time.
0.14 lb per MMBtu of steam
output or 1.7 lb per MWh; 3run average.
1 hr minimum sampling time.
0.12 lb per MMBtu of steam
output or 1.4 lb per MWh; 3run average.
1 hr minimum sampling time.
1.3E–01 lb per MMBtu of
steam output or 1.5 lb per
MWh; 3-run average.
1 hr minimum sampling time.
1.4 lb per MMBtu of steam output or 17 lb per MWh; 3-run
average.
1 hr minimum sampling time.
4.3E–02 lb per MMBtu of
steam output or 5.2E–01 lb
per MWh; or (2.8E–04 lb per
MMBtu of steam output or
3.4E–04 lb per MWh).
4.2E–01 lb per MMBtu of
steam output or 5.1 lb per
MWh.
3.7E–01 lb per MMBtu of
steam output or 4.5 lb per
MWh; or (4.6E–03 lb per
MMBtu of steam output or
5.6E–02 lb per MWh).
4.6E–01 lb per MMBtu of
steam output or 5.2 lb per
MWh; 3-run average.
Collect a minimum of 2 dscm
per run.
1.4E–01 lb per MMBtu of
steam output or 1.6 lb per
MWh; or (1.5E–03 lb per
MMBtu of steam output or
1.7E–02 lb per MWh).
E:\FR\FM\31JAR3.SGM
31JAR3
1 hr minimum sampling time.
Collect a minimum of 1 dscm
per run.
1 hr minimum sampling time.
Collect a minimum of 1 dscm
per run.
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
7197
TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS—
Continued
[Units with heat input capacity of 10 million Btu per hour or greater]
The emissions must not exceed the following emission
limits, except during startup
and shutdown . . .
If your boiler or process heater
is in this subcategory . . .
For the following
pollutants . . .
10. Suspension burners designed to burn biomass/biobased solid.
a. CO (or CEMS) .....................
b. Filterable PM (or TSM) ........
11. Dutch Ovens/Pile burners
designed to burn biomass/
bio-based solid.
a. CO (or CEMS) .....................
b. Filterable PM (or TSM) ........
12. Fuel cell units designed to
burn biomass/bio-based
solid.
a. CO .......................................
b. Filterable PM (or TSM) ........
13. Hybrid suspension grate
units designed to burn biomass/bio-based solid.
a. CO (or CEMS) .....................
b. Filterable PM (or TSM) ........
14. Units designed to burn liquid fuel.
The emissions must not exceed the following alternative
output-based limits, except
during startup and
shutdown . . .
2,400 ppm by volume on a dry
basis corrected to 3 percent
oxygen, 3-run average; or
(2,000 ppm by volume on a
dry basis corrected to 3 percent oxygen, 10-day rolling
average).
5.1E–02 lb per MMBtu of heat
input; or (6.5E–03 lb per
MMBtu of heat input).
1.9 lb per MMBtu of steam output or 27 lb per MWh; 3-run
average.
1 hr minimum sampling time.
5.2E–02 lb per MMBtu of
steam output or 7.1E–01 lb
per MWh; or (6.6E–03 lb per
MMBtu of steam output or
9.1E–02 lb per MWh).
8.4E–01 lb per MMBtu of
steam output or 8.4 lb per
MWh; 3-run average.
Collect a minimum of 2 dscm
per run.
770 ppm by volume on a dry
basis corrected to 3 percent
oxygen, 3-run average; or
(520 ppm by volume on a
dry basis corrected to 3 percent oxygen, 10-day rolling
average).
2.8E–01 lb per MMBtu of heat
input; or (2.0E–03 lb per
MMBtu of heat input).
1,100 ppm by volume on a dry
basis corrected to 3 percent
oxygen.
2.0E–02 lb per MMBtu of heat
input; or (5.8E–03 lb per
MMBtu of heat input).
2,800 ppm by volume on a dry
basis corrected to 3 percent
oxygen, 3-run average; or
(900 ppm by volume on a
dry basis corrected to 3 percent oxygen, 30-day rolling
average).
4.4E–01 lb per MMBtu of heat
input; or (4.5E–04 lb per
MMBtu of heat input).
3.9E–01 lb per MMBtu of
steam output or 3.9 lb per
MWh; or (2.8E–03 lb per
MMBtu of steam output or
2.8E–02 lb per MWh).
2.4 lb per MMBtu of steam output or 12 lb per MWh.
5.5E–02 lb per MMBtu of
steam output or 2.8E–01 lb
per MWh; or (1.6E–02 lb per
MMBtu of steam output or
8.1E–02 lb per MWh).
2.8 lb per MMBtu of steam output or 31 lb per MWh; 3-run
average.
5.5E–01 lb per MMBtu of
steam output or 6.2 lb per
MWh; or (5.7E–04 lb per
MMBtu of steam output or
6.3E–03 lb per MWh).
1.4E–03 lb per MMBtu of
steam output or 1.6E–02 lb
per MWh.
1.1E–03 lb per MMBtu of heat
input.
b. Mercury ................................
15. Units designed to burn
heavy liquid fuel.
a. HCl .......................................
2.0E–06 lb per MMBtu of heat
input.
2.5E–06 lb per MMBtu of
steam output or 2.8E–05 lb
per MWh.
a. CO .......................................
130 ppm by volume on a dry
basis corrected to 3 percent
oxygen, 3-run average.
6.2E–02 lb per MMBtu of heat
input; or (2.0E–04 lb per
MMBtu of heat input).
0.13 lb per MMBtu of steam
output or 1.4 lb per MWh; 3run average.
7.5E–02 lb per MMBtu of
steam output or 8.6E–01 lb
per MWh; or (2.5E–04 lb per
MMBtu of steam output or
2.8E–03 lb per MWh).
0.13 lb per MMBtu of steam
output or 1.4 lb per MWh.
b. Filterable PM (or TSM) ........
16. Units designed to burn light
liquid fuel.
a. CO .......................................
tkelley on DSK3SPTVN1PROD with
b. Filterable PM (or TSM) ........
17. Units designed to burn liquid fuel that are non-continental units.
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a. CO .......................................
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130 ppm by volume on a dry
basis corrected to 3 percent
oxygen.
7.9E–03 lb per MMBtu of heat
input; or (6.2E–05 lb per
MMBtu of heat input).
130 ppm by volume on a dry
basis corrected to 3 percent
oxygen,
3-run
average
based on stack test.
Frm 00061
Fmt 4701
Sfmt 4700
9.6E–03 lb per MMBtu of
steam output or 1.1E–01 lb
per MWh; or (7.5E–05 lb per
MMBtu of steam output or
8.6E–04 lb per MWh).
0.13 lb per MMBtu of steam
output or 1.4 lb per MWh; 3run average.
E:\FR\FM\31JAR3.SGM
31JAR3
Using this specified sampling
volume or test run
duration . . .
1 hr minimum sampling time.
Collect a minimum of 1 dscm
per run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm
per run.
1 hr minimum sampling time.
Collect a minimum of 1 dscm
per run.
For M26A, collect a minimum
of 2 dscm per run; for M26,
collect a minimum of 240 liters per run.
For M29, collect a minimum of
3 dscm per run; for M30A or
M30B collect a minimum
sample as specified in the
method, for ASTM D6784 b
collect a minimum of 2
dscm.
1 hr minimum sampling time.
Collect a minimum of 1 dscm
per run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm
per run.
1 hr minimum sampling time.
7198
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
TABLE 2 TO SUBPART DDDDD OF PART 63—EMISSION LIMITS FOR EXISTING BOILERS AND PROCESS HEATERS—
Continued
[Units with heat input capacity of 10 million Btu per hour or greater]
18. Units designed to burn gas
2 (other) gases.
The emissions must not exceed the following emission
limits, except during startup
and shutdown . . .
The emissions must not exceed the following alternative
output-based limits, except
during startup and
shutdown . . .
b. Filterable PM (or TSM) ........
If your boiler or process heater
is in this subcategory . . .
2.7E–01 lb per MMBtu of heat
input; or (8.6E–04 lb per
MMBtu of heat input).
a. CO .......................................
130 ppm by volume on a dry
basis corrected to 3 percent
oxygen.
1.7E–03 lb per MMBtu of heat
input.
3.3E–01 lb per MMBtu of
steam output or 3.8 lb per
MWh; or (1.1E–03 lb per
MMBtu of steam output or
1.2E–02 lb per MWh).
0.16 lb per MMBtu of steam
output or 1.0 lb per MWh.
For the following
pollutants . . .
b. HCl .......................................
2.9E–03 lb per MMBtu of
steam output or 1.8E–02 lb
per MWh.
c. Mercury ................................
7.9E–06 lb per MMBtu of heat
input.
1.4E–05 lb per MMBtu of
steam output or 8.3E–05 lb
per MWh.
d. Filterable PM (or TSM) ........
6.7E–03 lb per MMBtu of heat
input or (2.1E–04 lb per
MMBtu of heat input).
1.2E–02 lb per MMBtu of
steam output or 7.0E–02 lb
per MWh; or (3.5E–04 lb per
MMBtu of steam output or
2.2E–03 lb per MWh).
Using this specified sampling
volume or test run
duration . . .
Collect a minimum of 2 dscm
per run.
1 hr minimum sampling time.
For M26A, collect a minimum
of 2 dscm per run; for M26,
collect a minimum of 240 liters per run.
For M29, collect a minimum of
3 dscm per run; for M30A or
M30B, collect a minimum
sample as specified in the
method; for ASTM D6784 b
collect a minimum of 2
dscm.
Collect a minimum of 3 dscm
per run.
a If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant for at least 2 consecutive years show that your emissions are at or below this limit, you can skip testing according to § 63.7515 if all of the other provisions of § 63.7515 are met. For all other pollutants that do not contain a footnote a, your performance tests for this pollutant for at least 2 consecutive years must show that your emissions are at or below 75 percent of this limit in
order to qualify for skip testing.
b Incorporated by reference, see § 63.14.
■ 30. Table 3 to subpart DDDDD of part
63 is revised to read as follows:
As stated in § 63.7500, you must
comply with the following applicable
work practice standards:
TABLE 3 TO SUBPART DDDDD OF PART 63—WORK PRACTICE STANDARDS
If your unit is . . .
You must meet the following . . .
1. A new or existing boiler or process heater with a continuous oxygen
trim system that maintains an optimum air to fuel ratio, or a heat
input capacity of less than or equal to 5 million Btu per hour in any of
the following subcategories: unit designed to burn gas 1; unit designed to burn gas 2 (other); or unit designed to burn light liquid, or a
limited use boiler or process heater.
2. A new or existing boiler or process heater without a continuous oxygen trim system and with heat input capacity of less than 10 million
Btu per hour in the unit designed to burn heavy liquid or unit designed to burn solid fuel subcategories; or a new or existing boiler or
process heater with heat input capacity of less than 10 million Btu
per hour, but greater than 5 million Btu per hour, in any of the following subcategories: unit designed to burn gas 1; unit designed to
burn gas 2 (other); or unit designed to burn light liquid.
3. A new or existing boiler or process heater without a continuous oxygen trim system and with heat input capacity of 10 million Btu per
hour or greater.
Conduct a tune-up of the boiler or process heater every 5 years as
specified in § 63.7540.
tkelley on DSK3SPTVN1PROD with
4. An existing boiler or process heater located at a major source facility, not including limited use units.
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Conduct a tune-up of the boiler or process heater biennially as specified in § 63.7540.
Conduct a tune-up of the boiler or process heater annually as specified
in § 63.7540. Units in either the Gas 1 or Metal Process Furnace
subcategories will conduct this tune-up as a work practice for all regulated emissions under this subpart. Units in all other subcategories
will conduct this tune-up as a work practice for dioxins/furans.
Must have a one-time energy assessment performed by a qualified energy assessor. An energy assessment completed on or after January
1, 2008, that meets or is amended to meet the energy assessment
requirements in this table, satisfies the energy assessment requirement. A facility that operates under an energy management program
compatible with ISO 50001 that includes the affected units also satisfies the energy assessment requirement. The energy assessment
must include the following with extent of the evaluation for items a.
to e. appropriate for the on-site technical hours listed in § 63.7575:
a. A visual inspection of the boiler or process heater system.
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Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
7199
TABLE 3 TO SUBPART DDDDD OF PART 63—WORK PRACTICE STANDARDS—Continued
If your unit is . . .
You must meet the following . . .
5. An existing or new boiler or process heater subject to emission limits
in Table 1 or 2 or 11 through 13 to this subpart during startup.
6. An existing or new boiler or process heater subject to emission limits
in Tables 1 or 2 or 11 through 13 to this subpart during shutdown.
31. Table 4 to subpart DDDDD of part
63 is revised to read as follows:
■
b. An evaluation of operating characteristics of the boiler or process
heater systems, specifications of energy using systems, operating
and maintenance procedures, and unusual operating constraints.
c. An inventory of major energy use systems consuming energy from
affected boilers and process heaters and which are under the control
of the boiler/process heater owner/operator.
d. A review of available architectural and engineering plans, facility operation and maintenance procedures and logs, and fuel usage.
e. A review of the facility’s energy management practices and provide
recommendations for improvements consistent with the definition of
energy management practices, if identified.
f. A list of cost-effective energy conservation measures that are within
the facility’s control.
g. A list of the energy savings potential of the energy conservation
measures identified.
h. A comprehensive report detailing the ways to improve efficiency, the
cost of specific improvements, benefits, and the time frame for recouping those investments.
You must operate all CMS during startup.
For startup of a boiler or process heater, you must use one or a combination of the following clean fuels: natural gas, synthetic natural
gas, propane, distillate oil, syngas, ultra-low sulfur diesel, fuel oilsoaked rags, kerosene, hydrogen, paper, cardboard, refinery gas,
and liquefied petroleum gas.
If you start firing coal/solid fossil fuel, biomass/bio-based solids, heavy
liquid fuel, or gas 2 (other) gases, you must vent emissions to the
main stack(s) and engage all of the applicable control devices except
limestone injection in fluidized bed combustion (FBC) boilers, dry
scrubber, fabric filter, selective non-catalytic reduction (SNCR), and
selective catalytic reduction (SCR). You must start your limestone injection in FBC boilers, dry scrubber, fabric filter, SNCR, and SCR
systems as expeditiously as possible. Startup ends when steam or
heat is supplied for any purpose.
You must comply with all applicable emission limits at all times except
for startup or shutdown periods conforming with this work practice.
You must collect monitoring data during periods of startup, as specified in § 63.7535(b). You must keep records during periods of startup. You must provide reports concerning activities and periods of
startup, as specified in § 63.7555.
You must operate all CMS during shutdown.
While firing coal/solid fossil fuel, biomass/bio-based solids, heavy liquid
fuel, or gas 2 (other) gases during shutdown, you must vent emissions to the main stack(s) and operate all applicable control devices,
except limestone injection in FBC boilers, dry scrubber, fabric filter,
SNCR, and SCR.
You must comply with all applicable emissions limits at all times except
for startup or shutdown periods conforming with this work practice.
You must collect monitoring data during periods of shutdown, as
specified in § 63.7535(b). You must keep records during periods of
shutdown. You must provide reports concerning activities and periods of shutdown, as specified in § 63.7555.
As stated in § 63.7500, you must
comply with the applicable operating
limits:
TABLE 4 TO SUBPART DDDDD OF PART 63—OPERATING LIMITS FOR BOILERS AND PROCESS HEATERS
You must meet these operating limits . . .
1. Wet PM scrubber control on a boiler not
using a PM CPMS.
tkelley on DSK3SPTVN1PROD with
When complying with a Table 1, 2, 11, 12, or
13 numerical emission limit using . . .
Maintain the 30-day rolling average pressure drop and the 30-day rolling average liquid flow
rate at or above the lowest one-hour average pressure drop and the lowest one-hour average liquid flow rate, respectively, measured during the most recent performance test demonstrating compliance with the PM emission limitation according to § 63.7530(b) and Table 7
to this subpart.
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7200
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
TABLE 4 TO SUBPART DDDDD OF PART 63—OPERATING LIMITS FOR BOILERS AND PROCESS HEATERS—Continued
When complying with a Table 1, 2, 11, 12, or
13 numerical emission limit using . . .
You must meet these operating limits . . .
2. Wet acid gas (HCl) scrubber control on a
boiler not using a HCl CEMS.
Maintain the 30-day rolling average effluent pH at or above the lowest one-hour average pH
and the 30-day rolling average liquid flow rate at or above the lowest one-hour average liquid flow rate measured during the most recent performance test demonstrating compliance
with the HCl emission limitation according to § 63.7530(b) and Table 7 to this subpart.
a. Maintain opacity to less than or equal to 10 percent opacity (daily block average); or
3. Fabric filter control on units not using a PM
CPMS.
4. Electrostatic precipitator control on units not
using a PM CPMS.
5. Dry scrubber or carbon injection control on a
boiler not using a mercury CEMS.
6. Any other add-on air pollution control type on
units not using a PM CPMS.
7. Fuel analysis ...................................................
8. Performance testing .......................................
9. Oxygen analyzer system ................................
10. SO2 CEMS ....................................................
32. Table 5 to subpart DDDDD of part
63 is amended by:
■ a. Revising the entry for ‘‘1.
Particulate matter.’’
■ b. Remove the entry for ‘‘5. Dioxins/
Furans’’.
■ c. Redesignating the entries for ‘‘2.
Hydrogen chloride,’’ ‘‘3. Mercury,’’ and
■
b. Install and operate a bag leak detection system according to § 63.7525 and operate the fabric filter such that the bag leak detection system alert is not activated more than 5 percent of
the operating time during each 6-month period.
a. This option is for boilers and process heaters that operate dry control systems (i.e., an ESP
without a wet scrubber). Existing and new boilers and process heaters must maintain opacity to less than or equal to 10 percent opacity (daily block average); or
b. This option is only for boilers and process heaters not subject to PM CPMS or continuous
compliance with an opacity limit (i.e., COMS). Maintain the 30-day rolling average total secondary electric power input of the electrostatic precipitator at or above the operating limits
established during the performance test according to § 63.7530(b) and Table 7 to this subpart.
Maintain the minimum sorbent or carbon injection rate as defined in § 63.7575 of this subpart.
This option is for boilers and process heaters that operate dry control systems. Existing and
new boilers and process heaters must maintain opacity to less than or equal to 10 percent
opacity (daily block average).
Maintain the fuel type or fuel mixture such that the applicable emission rates calculated according to § 63.7530(c)(1), (2) and/or (3) is less than the applicable emission limits.
For boilers and process heaters that demonstrate compliance with a performance test, maintain the operating load of each unit such that it does not exceed 110 percent of the highest
hourly average operating load recorded during the most recent performance test.
For boilers and process heaters subject to a CO emission limit that demonstrate compliance
with an O2 analyzer system as specified in § 63.7525(a), maintain the 30-day rolling average
oxygen content at or above the lowest hourly average oxygen concentration measured during the most recent CO performance test, as specified in Table 8. This requirement does not
apply to units that install an oxygen trim system since these units will set the trim system to
the level specified in § 63.7525(a).
For boilers or process heaters subject to an HCl emission limit that demonstrate compliance
with an SO2 CEMS, maintain the 30-day rolling average SO2 emission rate at or below the
highest hourly average SO2 concentration measured during the most recent HCl performance test, as specified in Table 8.
‘‘4. CO’’ as ‘‘3. Hydrogen chloride,’’ ‘‘4.
Mercury,’’ and ‘‘5. CO,’’ respectively.
■ d. Revising the newly redesignated
entries for ‘‘4. Mercury’’ and ‘‘5. CO.’’
■ e. Add entry for ‘‘2. Total selected
metals.’’
The revisions and addition read as
follows:
As stated in § 63.7520, you must
comply with the following requirements
for performance testing for existing, new
or reconstructed affected sources:
TABLE 5 TO SUBPART DDDDD OF PART 63—PERFORMANCE TESTING REQUIREMENTS
To conduct a performance test for the following pollutant . . .
tkelley on DSK3SPTVN1PROD with
1. Filterable PM .........
2. TSM .......................
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You must . . .
Using . . .
a. Select sampling ports location and the number of traverse points.
b. Determine velocity and volumetric flow-rate
of the stack gas.
c. Determine oxygen or carbon dioxide concentration of the stack gas.
d. Measure the moisture content of the stack
gas.
e. Measure the PM emission concentration .....
Method 1 at 40 CFR part 60, appendix A–1 of this chapter.
f. Convert emissions concentration to lb per
MMBtu emission rates.
a. Select sampling ports location and the number of traverse points.
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Method 2, 2F, or 2G at 40 CFR part 60, appendix A–1 or A–2 to part
60 of this chapter.
Method 3A or 3B at 40 CFR part 60, appendix A–2 to part 60 of this
chapter, or ANSI/ASME PTC 19.10–1981.a
Method 4 at 40 CFR part 60, appendix A–3 of this chapter.
Method 5 or 17 (positive pressure fabric filters must use Method 5D)
at 40 CFR part 60, appendix A–3 or A–6 of this chapter.
Method 19 F-factor methodology at 40 CFR part 60, appendix A–7 of
this chapter.
Method 1 at 40 CFR part 60, appendix A–1 of this chapter.
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7201
TABLE 5 TO SUBPART DDDDD OF PART 63—PERFORMANCE TESTING REQUIREMENTS—Continued
To conduct a performance test for the following pollutant . . .
You must . . .
Using . . .
Method 2, 2F, or 2G at 40 CFR part 60, appendix A–1 or A–2 of this
chapter.
Method 3A or 3B at 40 CFR part 60, appendix A–1 of this chapter, or
ANSI/ASME PTC 19.10–1981.a
Method 4 at 40 CFR part 60, appendix A–3 of this chapter.
3. HCl .........................
b. Determine velocity and volumetric flow-rate
of the stack gas.
c. Determine oxygen or carbon dioxide concentration of the stack gas.
d. Measure the moisture content of the stack
gas.
e. Measure the TSM emission concentration ...
f. Convert emissions concentration to lb per
MMBtu emission rates.
a. Select sampling ports location and the number of traverse points.
b. Determine velocity and volumetric flow-rate
of the stack gas.
c. Determine oxygen or carbon dioxide concentration of the stack gas.
d. Measure the moisture content of the stack
gas.
e. Measure the HCl emission concentration .....
4. Mercury ..................
5. CO .........................
f. Convert emissions concentration to lb per
MMBtu emission rates.
a. Select sampling ports location and the number of traverse points.
b. Determine velocity and volumetric flow-rate
of the stack gas.
c. Determine oxygen or carbon dioxide concentration of the stack gas.
d. Measure the moisture content of the stack
gas.
e. Measure the mercury emission concentration.
f. Convert emissions concentration to lb per
MMBtu emission rates.
a. Select the sampling ports location and the
number of traverse points.
b. Determine oxygen concentration of the
stack gas.
c. Measure the moisture content of the stack
gas.
d. Measure the CO emission concentration .....
*
*
*
*
*
33. Table 6 to subpart DDDDD of part
63 is revised to read as follows:
As stated in § 63.7521, you must
comply with the following requirements
■
Method 29 at 40 CFR part 60, appendix A–8 of this chapter
Method 19 F-factor methodology at 40 CFR part 60, appendix A–7 of
this chapter.
Method 1 at 40 CFR part 60, appendix A–1 of this chapter.
Method 2, 2F, or 2G at 40 CFR part 60, appendix A–2 of this chapter.
Method 3A or 3B at 40 CFR part 60, appendix A–2 of this chapter, or
ANSI/ASME PTC 19.10–1981.a
Method 4 at 40 CFR part 60, appendix A–3 of this chapter.
Method 26 or 26A (M26 or M26A) at 40 CFR part 60, appendix A–8 of
this chapter.
Method 19 F-factor methodology at 40 CFR part 60, appendix A–7 of
this chapter.
Method 1 at 40 CFR part 60, appendix A–1 of this chapter.
Method 2, 2F, or 2G at 40 CFR part 60, appendix A–1 or A–2 of this
chapter.
Method 3A or 3B at 40 CFR part 60, appendix A–1 of this chapter, or
ANSI/ASME PTC 19.10–1981.a
Method 4 at 40 CFR part 60, appendix A–3 of this chapter.
Method 29, 30A, or 30B (M29, M30A, or M30B) at 40 CFR part 60,
appendix A–8 of this chapter or Method 101A at 40 CFR part 61,
appendix B of this chapter, or ASTM Method D6784.a
Method 19 F-factor methodology at 40 CFR part 60, appendix A–7 of
this chapter.
Method 1 at 40 CFR part 60, appendix A–1 of this chapter.
Method 3A or 3B at 40 CFR part 60, appendix A–3 of this chapter, or
ASTM D6522–00 (Reapproved 2005), or ANSI/ASME PTC 19.10–
1981.a
Method 4 at 40 CFR part 60, appendix A–3 of this chapter.
Method 10 at 40 CFR part 60, appendix A–4 of this chapter. Use a
measurement span value of 2 times the concentration of the applicable emission limit.
for fuel analysis testing for existing, new
or reconstructed affected sources.
However, equivalent methods (as
defined in § 63.7575) may be used in
lieu of the prescribed methods at the
discretion of the source owner or
operator:
TABLE 6 TO SUBPART DDDDD OF PART 63—FUEL ANALYSIS REQUIREMENTS
You must . . .
Using . . .
1. Mercury ..................
tkelley on DSK3SPTVN1PROD with
To conduct a fuel
analysis for the following pollutant . . .
a. Collect fuel samples ......................................
Procedure in § 63.7521(c) or ASTM D5192 a, or ASTM D7430 a, or
ASTM D6883 a, or ASTM D2234/D2234M a(for coal) or EPA 1631 or
EPA 1631E or ASTM D6323 a (for solid), or EPA 821–R–01–013
(for liquid or solid), or ASTM D4177 a (for liquid), or ASTM D4057 a
(for liquid), or equivalent.
Procedure in § 63.7521(d) or equivalent.
EPA SW–846–3050B a (for solid samples), EPA SW–846–3020A a (for
liquid samples), ASTM D2013/D2013M a (for coal), ASTM D5198 a
(for biomass), or EPA 3050 a (for solid fuel), or EPA 821–R–01–
013 a (for liquid or solid), or equivalent.
b. Composite fuel samples ................................
c. Prepare composited fuel samples .................
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TABLE 6 TO SUBPART DDDDD OF PART 63—FUEL ANALYSIS REQUIREMENTS—Continued
To conduct a fuel
analysis for the following pollutant . . .
You must . . .
Using . . .
d. Determine heat content of the fuel type .......
ASTM D5865 a (for coal) or ASTM E711 a (for biomass), or ASTM
D5864 a for liquids and other solids, or ASTM D240 a or equivalent.
ASTM D3173 a, ASTM E871 a, or ASTM D5864 a, or ASTM D240, or
ASTM D95 a (for liquid fuels), or ASTM D4006 a (for liquid fuels), or
ASTM D4177 a (for liquid fuels) or ASTM D4057 a (for liquid fuels),
or equivalent.
ASTM D6722 a (for coal), EPA SW–846–7471B a (for solid samples),
or EPA SW–846–7470A a (for liquid samples), or equivalent.
Equation 8 in § 63.7530.
e. Determine moisture content of the fuel type
2. HCl .........................
f. Measure mercury concentration in fuel sample.
g. Convert concentration into units of pounds
of mercury per MMBtu of heat content.
h. Calculate the mercury emission rate from
the boiler or process heater in units of
pounds per million Btu.
a. Collect fuel samples ......................................
b. Composite fuel samples ................................
c. Prepare composited fuel samples .................
d. Determine heat content of the fuel type .......
e. Determine moisture content of the fuel type
f. Measure chlorine concentration in fuel sample.
3. Mercury Fuel Specification for other
gas 1 fuels.
4. TSM for solid fuels
g. Convert concentrations into units of pounds
of HCl per MMBtu of heat content.
h. Calculate the HCl emission rate from the
boiler or process heater in units of pounds
per million Btu.
a. Measure mercury concentration in the fuel
sample and convert to units of micrograms
per cubic meter.
b. Measure mercury concentration in the exhaust gas when firing only the other gas 1
fuel is fired in the boiler or process heater.
a. Collect fuel samples ......................................
b. Composite fuel samples ................................
c. Prepare composited fuel samples .................
d. Determine heat content of the fuel type .......
e. Determine moisture content of the fuel type
tkelley on DSK3SPTVN1PROD with
f. Measure TSM concentration in fuel sample ..
g. Convert concentrations into units of pounds
of TSM per MMBtu of heat content.
h. Calculate the TSM emission rate from the
boiler or process heater in units of pounds
per million Btu.
a Incorporated
VerDate Mar<15>2010
Equations 10 and 12 in § 63.7530.
Procedure in § 63.7521(c) or ASTM D5192 a, or ASTM D7430 a, or
ASTM D6883 a, or ASTM D2234/D2234M a (for coal) or ASTM
D6323 a (for coal or biomass), ASTM D4177 a (for liquid fuels) or
ASTM D4057 a (for liquid fuels), or equivalent.
Procedure in § 63.7521(d) or equivalent.
EPA SW–846–3050B a (for solid samples), EPA SW–846–3020A a (for
liquid samples), ASTM D2013/D2013M§a (for coal), or ASTM
D5198§a (for biomass), or EPA 3050 a or equivalent.
ASTM D5865 a (for coal) or ASTM E711 a (for biomass), ASTM D5864,
ASTM D240 a or equivalent.
ASTM D3173 a or ASTM E871 a, or D5864 a, or ASTM D240 a, or
ASTM D95a (for liquid fuels), or ASTM D4006 a (for liquid fuels), or
ASTM D4177 a (for liquid fuels) or ASTM D4057 a (for liquid fuels) or
equivalent.
EPA SW–846–9250 a, ASTM D6721 a, ASTM D4208 a (for coal), or
EPA SW–846–5050 a or ASTM E776 a (for solid fuel), or EPA SW–
846–9056 a or SW–846–9076 a (for solids or liquids) or equivalent.
Equation 7 in § 63.7530.
Equations 10 and 11 in § 63.7530.
Method 30B (M30B) at 40 CFR part 60, appendix A–8 of this chapter
or ASTM D5954 a, ASTM D6350 a, ISO 6978–1:2003(E) a, or ISO
6978–2:2003(E) a, or EPA–1631 a or equivalent.
Method 29, 30A, or 30B (M29, M30A, or M30B) at 40 CFR part 60,
appendix A–8 of this chapter or Method 101A or Method 102 at 40
CFR part 61, appendix B of this chapter, or ASTM Method D6784 a
or equivalent.
Procedure in § 63.7521(c) or ASTM D5192 a, or ASTM D7430 a, or
ASTM D6883 a, or ASTM D2234/D2234M a (for coal) or ASTM
D6323 a (for coal or biomass), or ASTM D4177 a,(for liquid fuels)or
ASTM D4057 a (for liquid fuels),or equivalent.
Procedure in § 63.7521(d) or equivalent.
EPA SW–846–3050B a (for solid samples), EPA SW–846–3020A a (for
liquid samples), ASTM D2013/D2013M a (for coal), ASTM D5198 a
or TAPPI T266 a (for biomass), or EPA 3050 a or equivalent.
ASTM D5865 a (for coal) or ASTM E711 a (for biomass), or ASTM
D5864 a for liquids and other solids, or ASTM D240 a or equivalent.
ASTM D3173 a or ASTM E871 a, or D5864, or ASTM D240 a, or ASTM
D95 a (for liquid fuels), or ASTM D4006a (for liquid fuels), or ASTM
D4177 a (for liquid fuels) or ASTM D4057 a (for liquid fuels), or
equivalent.
ASTM D3683 a, or ASTM D4606 a, or ASTM D6357 a or EPA
200.8 a or EPA SW–846–6020 a, or EPA SW–846–6020A a, or EPA
SW–846–6010C a, EPA 7060 a or EPA 7060A a (for arsenic only), or
EPA SW–846–7740 a (for selenium only).
Equation 9 in § 63.7530.
Equations 10 and 13 in § 63.7530.
by reference, see § 63.14.
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Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
34. Table 7 to subpart DDDDD of part
63 is amended by:
■ a. Revising the entry for ‘‘1.
Particulate matter or mercury,’’.
■ b. Revising the entry for ‘‘2. Hydrogen
Chloride,’’.
■
c. Revising the entry for ‘‘3.
Mercury,’’.
■ d. Revising the entry for ‘‘4. Carbon
monoxide’’.
The revisions read as follows:
■
7203
As stated in § 63.7520, you must
comply with the following requirements
for establishing operating limits:
TABLE 7 TO SUBPART DDDDD OF PART 63—ESTABLISHING OPERATING LIMITS
If you have an applicable emission limit for . . .
And your operating limits are
based on . . .
You must . . .
Using . . .
According to the following requirements
1. PM, TSM, or mercury ...........
a. Wet scrubber operating parameters.
i. Establish a site-specific minimum scrubber pressure
drop and minimum flow rate
operating limit according to
§ 63.7530(b).
(1) Data from the scrubber
pressure drop and liquid flow
rate monitors and the PM or
mercury performance test.
b. Electrostatic precipitator operating parameters (option
only for units that operate
wet scrubbers).
i. Establish a site-specific minimum total secondary electric power input according to
§ 63.7530(b).
(1) Data from the voltage and
secondary amperage monitors during the PM or mercury performance test.
a. Wet scrubber operating parameters.
i. Establish site-specific minimum pressure drop, effluent
pH, and flow rate operating
limits
according
to
§ 63.7530(b).
(1) Data from the pressure
drop, pH, and liquid flow-rate
monitors and the HCl performance test.
b. Dry scrubber operating parameters.
i. Establish a site-specific minimum sorbent injection rate
operating limit according to
§ 63.7530(b). If different acid
gas sorbents are used during the HCl performance
test, the average value for
each sorbent becomes the
site-specific operating limit
for that sorbent.
(1) Data from the sorbent injection rate monitors and
HCl or mercury performance
test.
(a) You must collect scrubber
pressure drop and liquid flow
rate data every 15 minutes
during the entire period of
the performance tests.
(b) Determine the lowest hourly average scrubber pressure drop and liquid flow
rate by computing the hourly
averages using all of the 15minute readings taken during each performance test.
(a) You must collect secondary
voltage and secondary amperage for each ESP cell
and calculate total secondary electric power input
data every 15 minutes during the entire period of the
performance tests.
(b) Determine the average
total secondary electric
power input by computing
the hourly averages using all
of the 15-minute readings
taken during each performance test.
(a) You must collect pH and
liquid flow-rate data every 15
minutes during the entire period of the performance
tests.
(b) Determine the hourly average pH and liquid flow rate
by computing the hourly
averages using all of the 15minute readings taken during each performance test.
(a) You must collect sorbent
injection rate data every 15
minutes during the entire period of the performance
tests.
tkelley on DSK3SPTVN1PROD with
2. HCl .......................................
c. Alternative Maximum SO2
emission rate.
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i. Establish a site-specific maximum SO2 emission rate operating limit according to
§ 63.7530(b).
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(1) Data from SO2 CEMS and
the HCl performance test.
E:\FR\FM\31JAR3.SGM
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(b) Determine the hourly average sorbent injection rate by
computing the hourly averages using all of the 15minute readings taken during each performance test.
(c) Determine the lowest hourly average of the three test
run averages established
during the performance test
as your operating limit.
When your unit operates at
lower loads, multiply your
sorbent injection rate by the
load fraction (e.g., for 50
percent load, multiply the injection rate operating limit by
0.5) to determine the required injection rate.
(a) You must collect the SO2
emissions data according to
§ 63.7525(m) during the
most recent HCl performance tests.
7204
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TABLE 7 TO SUBPART DDDDD OF PART 63—ESTABLISHING OPERATING LIMITS—Continued
If you have an applicable emission limit for . . .
And your operating limits are
based on . . .
You must . . .
According to the following requirements
Using . . .
3. Mercury ................................
a. Activated carbon injection ...
i. Establish a site-specific minimum activated carbon injection rate operating limit according to § 63.7530(b).
(1) Data from the activated
carbon rate monitors and
mercury performance test.
4. Carbon monoxide .................
a. Oxygen ................................
i. Establish a unit-specific limit
for minimum oxygen level
according to § 63.7520.
(1) Data from the oxygen analyzer system specified in
§ 63.7525(a).
*
*
*
35. Table 8 to subpart DDDDD of part
63 is revised to read as follows:
■
*
*
As stated in § 63.7540, you must show
continuous compliance with the
emission limitations for each boiler or
(b) The maximum SO2 emission rate is equal to the lowest hourly average SO2
emission rate measured during the most recent HCl performance tests.
(a) You must collect activated
carbon injection rate data
every 15 minutes during the
entire period of the performance tests.
(b) Determine the hourly average activated carbon injection rate by computing the
hourly averages using all of
the 15-minute readings
taken during each performance test.
(c) Determine the lowest hourly average established during the performance test as
your operating limit. When
your unit operates at lower
loads, multiply your activated
carbon injection rate by the
load fraction (e.g., actual
heat input divided by heat
input during performance
test, for 50 percent load,
multiply the injection rate operating limit by 0.5) to determine the required injection
rate.
(a) You must collect oxygen
data every 15 minutes during the entire period of the
performance tests.
(b) Determine the hourly average oxygen concentration by
computing the hourly averages using all of the 15minute readings taken during each performance test.
(c) Determine the lowest hourly average established during the performance test as
your minimum operating
limit.
*
*
process heater according to the
following:
TABLE 8 TO SUBPART DDDDD OF PART 63—DEMONSTRATING CONTINUOUS COMPLIANCE
If you must meet the following operating limits
or work practice standards . . .
You must demonstrate continuous compliance by . . .
1. Opacity ............................................................
a. Collecting the opacity monitoring system data according to § 63.7525(c) and § 63.7535; and
b. Reducing the opacity monitoring data to 6-minute averages; and
c. Maintaining opacity to less than or equal to 10 percent (daily block average).
a. Collecting the PM CPMS output data according to § 63.7525;
b. Reducing the data to 30-day rolling averages; and
c. Maintaining the 30-day rolling average PM CPMS output data to less than the operating
limit established during the performance test according to § 63.7530(b)(4).
Installing and operating a bag leak detection system according to § 63.7525 and operating the
fabric filter such that the requirements in § 63.7540(a)(9) are met.
a. Collecting the pressure drop and liquid flow rate monitoring system data according to
§§ 63.7525 and 63.7535; and
b. Reducing the data to 30-day rolling averages; and
c. Maintaining the 30-day rolling average pressure drop and liquid flow-rate at or above the
operating limits established during the performance test according to § 63.7530(b).
a. Collecting the pH monitoring system data according to §§ 63.7525 and 63.7535; and
2. PM CPMS .......................................................
tkelley on DSK3SPTVN1PROD with
3. Fabric Filter Bag Leak Detection Operation ...
4. Wet Scrubber Pressure Drop and Liquid
Flow-rate.
5. Wet Scrubber pH ............................................
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TABLE 8 TO SUBPART DDDDD OF PART 63—DEMONSTRATING CONTINUOUS COMPLIANCE—Continued
If you must meet the following operating limits
or work practice standards . . .
6. Dry Scrubber Sorbent or Carbon Injection
Rate.
7. Electrostatic Precipitator Total Secondary
Electric Power Input.
8. Emission limits using fuel analysis .................
9. Oxygen content ..............................................
10. Boiler or process heater operating load .......
11. SO2 emissions using SO2 CEMS .................
36. Table 9 to subpart DDDDD of part
63 is amended by revising the entry for
You must demonstrate continuous compliance by . . .
b. Reducing the data to 30-day rolling averages; and
c. Maintaining the 30-day rolling average pH at or above the operating limit established during
the performance test according to § 63.7530(b).
a. Collecting the sorbent or carbon injection rate monitoring system data for the dry scrubber
according to §§ 63.7525 and 63.7535; and
b. Reducing the data to 30-day rolling averages; and
c. Maintaining the 30-day rolling average sorbent or carbon injection rate at or above the minimum sorbent or carbon injection rate as defined in § 63.7575.
a. Collecting the total secondary electric power input monitoring system data for the electrostatic precipitator according to §§ 63.7525 and 63.7535; and
b. Reducing the data to 30-day rolling averages; and
c. Maintaining the 30-day rolling average total secondary electric power input at or above the
operating limits established during the performance test according to § 63.7530(b).
a. Conduct monthly fuel analysis for HCl or mercury or TSM according to Table 6 to this subpart; and
b. Reduce the data to 12-month rolling averages; and
c. Maintain the 12-month rolling average at or below the applicable emission limit for HCl or
mercury or TSM in Tables 1 and 2 or 11 through 13 to this subpart.
a. Continuously monitor the oxygen content using an oxygen analyzer system according to
§ 63.7525(a). This requirement does not apply to units that install an oxygen trim system
since these units will set the trim system to the level specified in § 63.7525(a)(2).
b. Reducing the data to 30-day rolling averages; and
c. Maintain the 30-day rolling average oxygen content at or above the lowest hourly average
oxygen level measured during the most recent CO performance test.
a. Collecting operating load data or steam generation data every 15 minutes.
b. Maintaining the operating load such that it does not exceed 110 percent of the highest hourly average operating load recorded during the most recent performance test according to
§ 63.7520(c).
a. Collecting the SO2 CEMS output data according to § 63.7525;
b. Reducing the data to 30-day rolling averages; and
c. Maintaining the 30-day rolling average SO2 CEMS emission rate to a level at or below the
minimum hourly SO2 rate measured during the most recent HCl performance test according
to § 63.7530.
‘‘1. Compliance report’’ to read as
follows:
■
As stated in § 63.7550, you must
comply with the following requirements
for reports:
TABLE 9 TO SUBPART DDDDD OF PART 63—REPORTING REQUIREMENTS
You must submit a(n)
The report must contain . . .
You must submit the report . . .
1. Compliance report .....................
a. Information required in § 63.7550(c)(1) through
(5); and
Semiannually, annually, biennially, or every 5 years
according to the requirements in § 63.7550(b).
*
*
*
37. Table 10 to subpart DDDDD of part
63 is amended by:
■ a. Revising the entry for ‘‘§ 63.6(i)’’.
■ b. Revising the entry for ‘‘§ 63.7(e)(1)’’.
■ c. Revising the entry for ‘‘63.8(g)’’.
■
*
*
d. Revising the entry for ‘‘§ 63.10(e)
and (f)’’.
■ e. Adding an entry for ‘‘§ 63.10(e)’’.
The revisions and addition read as
follows.
■
*
*
As stated in § 63.7565, you must
comply with the applicable General
Provisions according to the following:
TABLE 10 TO SUBPART DDDDD OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART DDDDD
Citation
Subject
tkelley on DSK3SPTVN1PROD with
*
§ 63.6(i) ......................
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Applies to subpart DDDDD
*
*
*
*
*
*
Extension of compliance ................................... Yes. Note: Facilities may also request extensions of compliance for
the installation of combined heat and power, waste heat recovery,
or gas pipeline or fuel feeding infrastructure as a means of complying with this subpart.
18:47 Jan 30, 2013
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31JAR3
7206
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
TABLE 10 TO SUBPART DDDDD OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART DDDDD—
Continued
Citation
Subject
Applies to subpart DDDDD
*
§ 63.7(e)(1) .................
*
*
*
*
*
*
Conditions for conducting performance tests ... No. Subpart DDDDD specifies conditions for conducting performance
tests at § 63.7520(a) to (c).
*
§ 63.8(g) .....................
*
*
*
Reduction of monitoring data ............................ Yes.
*
*
*
*
§ 63.10(e) ...................
*
*
*
Additional reporting requirements for sources Yes.
with CMS.
Waiver of recordkeeping or reporting require- Yes.
ments.
*
*
*
*
*
*
§ 63.10(f) ....................
*
*
*
*
38. Add Table 11 to subpart DDDDD
of part 63 to read as follows:
■
TABLE 11 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS
AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER JUNE 4, 2010, AND BEFORE MAY 20, 2011
For the following pollutants . . .
The emissions must not exceed the
following emission limits, except during periods of startup and shutdown
. . .
1. Units in all subcategories designed
to burn solid fuel.
a. HCl ........................
0.022 lb per MMBtu of heat input .......
2. Units in all subcategories designed
to burn solid fuel that combust at
least 10 percent biomass/bio-based
solids on an annual heat input basis
and less than 10 percent coal/solid
fossil fuels on an annual heat input
basis.
3. Units in all subcategories designed
to burn solid fuel that combust at
least 10 percent coal/solid fossil
fuels on an annual heat input basis
and less than 10 percent biomass/
bio-based solids on an annual heat
input basis.
4. Units designed to burn coal/solid
fossil fuel.
a. Mercury .................
8.0E–07 a lb per MMBtu of heat input
a. Mercury .................
2.0E–06 lb per MMBtu of heat input ...
For M29, collect a minimum of 4 dscm
per run; for M30A or M30B, collect
a minimum sample as specified in
the method; for ASTM D6784 b collect a minimum of 4 dscm.
a. Filterable PM (or
TSM).
a. Carbon monoxide
(CO) (or CEMS).
6. Stokers designed to burn coal/solid
fossil fuel.
a. CO (or CEMS) .......
7. Fluidized bed units designed to
burn coal/solid fossil fuel.
a. CO (or CEMS) .......
1.1E–03 lb per MMBtu of heat input;
or (2.3E–05 lb per MMBtu of heat
input).
130 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (320 ppm by volume on a dry basis corrected to 3
percent oxygen, 30-day rolling average).
130 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (340 ppm by volume on a dry basis corrected to 3
percent oxygen, 10-day rolling average).
130 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (230 ppm by volume on a dry basis corrected to 3
percent oxygen, 30-day rolling average).
Collect a minimum of 3 dscm per run.
5. Pulverized coal boilers designed to
burn coal/solid fossil fuel.
tkelley on DSK3SPTVN1PROD with
If your boiler or process heater is in
this subcategory . . .
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18:47 Jan 30, 2013
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E:\FR\FM\31JAR3.SGM
Using this specified sampling volume
or test run duration . . .
For M26A, collect a minimum of 1
dscm per run; for M26 collect a
minimum of 120 liters per run.
For M29, collect a minimum of 4 dscm
per run; for M30A or M30B, collect
a minimum sample as specified in
the method; for ASTM D6784 b collect a minimum of 4 dscm.
1 hr minimum sampling time.
1 hr minimum sampling time.
1 hr minimum sampling time.
31JAR3
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
7207
TABLE 11 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS
AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER JUNE 4, 2010, AND BEFORE MAY 20, 2011—Continued
If your boiler or process heater is in
this subcategory . . .
For the following pollutants . . .
8. Fluidized bed units with an integrated heat exchanger designed to
burn coal/solid fossil fuel.
a. CO (or CEMS) .......
9.
a. CO (or CEMS) .......
Stokers/sloped grate/others designed to burn wet biomass fuel.
b. Filterable PM (or
TSM).
10. Stokers/sloped grate/others designed to burn kiln-dried biomass
fuel.
a. CO .........................
b. Filterable PM (or
TSM).
11. Fluidized bed units designed to
burn biomass/bio-based solids.
a. CO (or CEMS) .......
b. Filterable PM (or
TSM).
12. Suspension burners designed to
burn biomass/bio-based solids.
a. CO (or CEMS) .......
b. Filterable PM (or
TSM).
13. Dutch Ovens/Pile burners designed to burn biomass/bio-based
solids.
a. CO (or CEMS) .......
b. Filterable PM (or
TSM).
14. Fuel cell units designed to burn
biomass/bio-based solids.
a. CO .........................
b. Filterable PM (or
TSM).
tkelley on DSK3SPTVN1PROD with
15. Hybrid suspension grate boiler designed to burn biomass/bio-based
solids.
a. CO (or CEMS) .......
b. Filterable PM (or
TSM).
16. Units designed to burn liquid fuel ..
VerDate Mar<15>2010
18:47 Jan 30, 2013
a. HCl ........................
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Frm 00071
The emissions must not exceed the
following emission limits, except during periods of startup and shutdown
. . .
Using this specified sampling volume
or test run duration . . .
140 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (150 ppm by volume on a dry basis corrected to 3
percent oxygen, 30-day rolling average).
620 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (390 ppm by volume on a dry basis corrected to 3
percent oxygen, 30-day rolling average).
3.0E–02 lb per MMBtu of heat input;
or (2.6E–05 lb per MMBtu of heat
input).
560 ppm by volume on a dry basis
corrected to 3 percent oxygen.
1 hr minimum sampling time.
3.0E–02 lb per MMBtu of heat input;
or (4.0E–03 lb per MMBtu of heat
input).
230 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (310 ppm by volume on a dry basis corrected to 3
percent oxygen, 30-day rolling average).
9.8E–03 lb per MMBtu of heat input;
or (8.3E–05 a lb per MMBtu of heat
input).
2,400 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (2,000 ppm by volume on a dry basis corrected to 3
percent oxygen, 10-day rolling average).
3.0E–02 lb per MMBtu of heat input;
or (6.5E–03 lb per MMBtu of heat
input).
1,010 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (520 ppm by volume on a dry basis corrected to 3
percent oxygen, 10-day rolling average).
8.0E–03 lb per MMBtu of heat input;
or (3.9E–05 lb per MMBtu of heat
input).
910 ppm by volume on a dry basis
corrected to 3 percent oxygen.
2.0E–02 lb per MMBtu of heat input;
or (2.9E–05 lb per MMBtu of heat
input).
1,100 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (900 ppm by volume on a dry basis corrected to 3
percent oxygen, 30-day rolling average).
2.6E–02 lb per MMBtu of heat input;
or (4.4E–04 lb per MMBtu of heat
input).
4.4E–04 lb per MMBtu of heat input ...
Collect a minimum of 2 dscm per run.
Fmt 4701
Sfmt 4700
E:\FR\FM\31JAR3.SGM
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run.
For M26A: Collect a minimum of 2
dscm per run; for M26, collect a
minimum of 240 liters per run.
31JAR3
7208
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
TABLE 11 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS
AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER JUNE 4, 2010, AND BEFORE MAY 20, 2011—Continued
The emissions must not exceed the
following emission limits, except during periods of startup and shutdown
. . .
4.8E–07 a lb per MMBtu of heat input
a. CO .........................
b. HCl ........................
130 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average.
1.3E–02 lb per MMBtu of heat input;
or (7.5E–05 lb per MMBtu of heat
input).
130 ppm by volume on a dry basis
corrected to 3 percent oxygen.
2.0E–03 a lb per MMBtu of heat input;
or (2.9E–05 lb per MMBtu of heat
input).
130 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average based on stack test.
2.3E–02 lb per MMBtu of heat input;
or (8.6E–04 lb per MMBtu of heat
input).
130 ppm by volume on a dry basis
corrected to 3 percent oxygen.
1.7E–03 lb per MMBtu of heat input ...
c. Mercury ..................
7.9E–06 lb per MMBtu of heat input ...
d. Filterable PM (or
TSM).
17. Units designed to burn heavy liquid fuel.
For the following pollutants . . .
b. Mercury .................
If your boiler or process heater is in
this subcategory . . .
6.7E–03 lb per MMBtu of heat input;
or (2.1E–04 lb per MMBtu of heat
input).
b. Filterable PM (or
TSM).
18. Units designed to burn light liquid
fuel.
a. CO .........................
b. Filterable PM (or
TSM).
19. Units designed to burn liquid fuel
that are non-continental units.
a. CO .........................
b. Filterable PM (or
TSM).
20. Units designed to burn gas 2
(other) gases.
a. CO .........................
Using this specified sampling volume
or test run duration . . .
For M29, collect a minimum of 4 dscm
per run; for M30A or M30B, collect
a minimum sample as specified in
the method; for ASTM D6784 b collect a minimum of 4 dscm.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run
1 hr minimum sampling time.
Collect a minimum of 4 dscm per run
1 hr minimum sampling time.
For M26A, collect a minimum of 2
dscm per run; for M26, collect a
minimum of 240 liters per run.
For M29, collect a minimum of 3 dscm
per run; for M30A or M30B, collect
a minimum sample as specified in
the method; for ASTM D6784 b collect a minimum of 3 dscm.
Collect a minimum of 3 dscm per run
a If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant for at least 2 consecutive years
show that your emissions are at or below this limit, you can skip testing according to § 63.7515 if all of the other provisions of § 63.7515 are met.
For all other pollutants that do not contain a footnote ‘‘a’’, your performance tests for this pollutant for at least 2 consecutive years must show
that your emissions are at or below 75 percent of this limit in order to qualify for skip testing.
b Incorporated by reference, see § 63.14.
39. Add Table 12 to subpart DDDDD
of part 63 to read as follows:
■
TABLE 12 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS
AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER MAY 20, 2011, AND BEFORE DECEMBER 23, 2011
For the following pollutants . . .
The emissions must not exceed the
following emission limits, except during periods of startup and shutdown
. . .
1. Units in all subcategories designed
to burn solid fuel.
a. HCl ........................
0.022 lb per MMBtu of heat input .......
b. Mercury .................
tkelley on DSK3SPTVN1PROD with
If your boiler or process heater is in
this subcategory . . .
3.5E–06 a lb per MMBtu of heat input
a. Filterable PM (or
TSM).
1.1E–03 lb per MMBtu of heat input;
or (2.3E–05 lb per MMBtu of heat
input).
2. Units design to burn coal/solid fossil
fuel.
VerDate Mar<15>2010
18:47 Jan 30, 2013
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PO 00000
Frm 00072
Fmt 4701
Sfmt 4700
E:\FR\FM\31JAR3.SGM
Using this specified sampling volume
or test run duration . . .
For M26A, collect a minimum of 1
dscm per run; for M26 collect a
minimum of 120 liters per run.
For M29, collect a minimum of 3 dscm
per run; for M30A or M30B, collect
a minimum sample as specified in
the method; for ASTM D6784 b collect a minimum of 3 dscm.
Collect a minimum of 3 dscm per run.
31JAR3
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
7209
TABLE 12 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS
AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER MAY 20, 2011, AND BEFORE DECEMBER 23, 2011—Continued
If your boiler or process heater is in
this subcategory . . .
For the following pollutants . . .
3. Pulverized coal boilers designed to
burn coal/solid fossil fuel.
a. Carbon monoxide
(CO) (or CEMS).
4. Stokers designed to burn coal/solid
fossil fuel.
a. CO (or CEMS) .......
5. Fluidized bed units designed to
burn coal/solid fossil fuel.
a. CO (or CEMS) .......
6. Fluidized bed units with an integrated heat exchanger designed to
burn coal/solid fossil fuel.
a. CO (or CEMS) .......
7.
a. CO (or CEMS) .......
Stokers/sloped grate/others designed to burn wet biomass fuel.
b. Filterable PM (or
TSM).
8.
Stokers/sloped grate/others designed to burn kiln-dried biomass
fuel.
a. CO .........................
b. Filterable PM (or
TSM).
9. Fluidized bed units designed to
burn biomass/bio-based solids.
a. CO (or CEMS) .......
b. Filterable PM (or
TSM).
10. Suspension burners designed to
burn biomass/bio-based solids.
a. CO (or CEMS) .......
b. Filterable PM (or
TSM).
tkelley on DSK3SPTVN1PROD with
11. Dutch Ovens/Pile burners designed to burn biomass/bio-based
solids.
a. CO (or CEMS) .......
b. Filterable PM (or
TSM).
VerDate Mar<15>2010
18:47 Jan 30, 2013
Jkt 229001
PO 00000
Frm 00073
The emissions must not exceed the
following emission limits, except during periods of startup and shutdown
. . .
Using this specified sampling volume
or test run duration . . .
130 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (320 ppm by volume on a dry basis corrected to 3
percent oxygen, 30-day rolling average).
130 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (340 ppm by volume on a dry basis corrected to 3
percent oxygen, 10-day rolling average).
130 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (230 ppm by volume on a dry basis corrected to 3
percent oxygen, 30-day rolling average).
140 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (150 ppm by volume on a dry basis corrected to 3
percent oxygen, 30-day rolling average).
620 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (390 ppm by volume on a dry basis corrected to 3
percent oxygen, 30-day rolling average).
3.0E–02 lb per MMBtu of heat input;
or (2.6E–05 lb per MMBtu of heat
input).
460 ppm by volume on a dry basis
corrected to 3 percent oxygen.
1 hr minimum sampling time.
3.0E–02 lb per MMBtu of heat input;
or (4.0E–03 lb per MMBtu of heat
input).
260 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (310 ppm by volume on a dry basis corrected to 3
percent oxygen, 30-day rolling average).
9.8E–03 lb per MMBtu of heat input;
or (8.3E–05 a lb per MMBtu of heat
input).
2,400 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (2,000 ppm by volume on a dry basis corrected to 3
percent oxygen, 10-day rolling average).
3.0E–02 lb per MMBtu of heat input;
or (6.5E–03 lb per MMBtu of heat
input).
470 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (520 ppm by volume on a dry basis corrected to 3
percent oxygen, 10-day rolling average).
3.2E–03 lb per MMBtu of heat input;
or (3.9E–05 lb per MMBtu of heat
input).
Collect a minimum of 2 dscm per run.
Fmt 4701
Sfmt 4700
E:\FR\FM\31JAR3.SGM
1 hr minimum sampling time.
1 hr minimum sampling time.
1 hr minimum sampling time.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run.
31JAR3
7210
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
TABLE 12 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS
AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER MAY 20, 2011, AND BEFORE DECEMBER 23, 2011—Continued
If your boiler or process heater is in
this subcategory . . .
For the following pollutants . . .
12. Fuel cell units designed to burn
biomass/bio-based solids.
a. CO .........................
The emissions must not exceed the
following emission limits, except during periods of startup and shutdown
. . .
a. HCl ........................
910 ppm by volume on a dry basis
corrected to 3 percent oxygen.
2.0E–02 lb per MMBtu of heat input;
or (2.9E–05 lb per MMBtu of heat
input).
1,500 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (900 ppm by volume on a dry basis corrected to 3
percent oxygen, 30-day rolling average).
2.6E–02 lb per MMBtu of heat input;
or (4.4E–04 lb per MMBtu of heat
input).
4.4E–04 lb per MMBtu of heat input ...
b. Mercury .................
4.8E–07 a lb per MMBtu of heat input
a. CO .........................
b. HCl ........................
130 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average.
1.3E–02 lb per MMBtu of heat input;
or (7.5E–05 lb per MMBtu of heat
input).
130 ppm by volume on a dry basis
corrected to 3 percent oxygen.
1.3E–03 a lb per MMBtu of heat input;
or (2.9E–05 lb per MMBtu of heat
input).
130 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average based on stack test.
2.3E–02 lb per MMBtu of heat input;
or (8.6E–04 lb per MMBtu of heat
input).
130 ppm by volume on a dry basis
corrected to 3 percent oxygen.
1.7E–03 lb per MMBtu of heat input ...
c. Mercury ..................
7.9E–06 lb per MMBtu of heat input ...
d. Filterable PM (or
TSM).
6.7E–03 lb per MMBtu of heat input;
or (2.1E–04 lb per MMBtu of heat
input).
b. Filterable PM (or
TSM).
13. Hybrid suspension grate boiler designed to burn biomass/bio-based
solids.
a. CO (or CEMS) .......
b. Filterable PM (or
TSM).
14. Units designed to burn liquid fuel ..
15. Units designed to burn heavy liquid fuel.
b. Filterable PM (or
TSM).
16. Units designed to burn light liquid
fuel.
a. CO .........................
b. Filterable PM (or
TSM).
17. Units designed to burn liquid fuel
that are non-continental units.
a. CO .........................
b. Filterable PM (or
TSM).
18. Units designed to burn gas 2
(other) gases.
a. CO .........................
Using this specified sampling volume
or test run duration . . .
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run.
For M26A: Collect a minimum of 2
dscm per run; for M26, collect a
minimum of 240 liters per run.
For M29, collect a minimum of 4 dscm
per run; for M30A or M30B, collect
a minimum sample as specified in
the method; for ASTM D6784 b collect a minimum of 4 dscm.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 4 dscm per run.
1 hr minimum sampling time.
For M26A, Collect a minimum of 2
dscm per run; for M26, collect a
minimum of 240 liters per run.
For M29, collect a minimum of 3 dscm
per run; for M30A or M30B, collect
a minimum sample as specified in
the method; for ASTM D6784 b collect a minimum of 3 dscm.
Collect a minimum of 3 dscm per run.
a If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant for at least 2 consecutive years
show that your emissions are at or below this limit, you can skip testing according to § 63.7515 if all of the other provision of § 63.7515 are met.
For all other pollutants that do not contain a footnote ‘‘a’’, your performance tests for this pollutant for at least 2 consecutive years must show
that your emissions are at or below 75 percent of this limit in order to qualify for skip testing.
b Incorporated by reference, see § 63.14.
40. Add Table 13 to subpart DDDDD
of part 63 to read as follows:
tkelley on DSK3SPTVN1PROD with
■
VerDate Mar<15>2010
18:47 Jan 30, 2013
Jkt 229001
PO 00000
Frm 00074
Fmt 4701
Sfmt 4700
E:\FR\FM\31JAR3.SGM
31JAR3
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
7211
TABLE 13 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS
AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER DECEMBER 23, 2011, AND
BEFORE JANUARY 31, 2013
If your boiler or process heater is in
this subcategory . . .
For the following pollutants . . .
The emissions must not exceed the
following emission limits, except during periods of startup and shutdown
. . .
1. Units in all subcategories designed
to burn solid fuel.
a. HCl ........................
0.022 lb per MMBtu of heat input .......
b. Mercury .................
8.6E–07 a lb per MMBtu of heat input
a. Carbon monoxide
(CO) (or CEMS).
130 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (320 ppm by volume on a dry basis corrected to 3
percent oxygen, 30-day rolling average).
1.1E–03 lb per MMBtu of heat input;
or (2.8E–05 lb per MMBtu of heat
input).
130 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (340 ppm by volume on a dry basis corrected to 3
percent oxygen, 10-day rolling average).
2.8E–02 lb per MMBtu of heat input;
or (2.3E–05 lb per MMBtu of heat
input).
130 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (230 ppm by volume on a dry basis corrected to 3
percent oxygen, 30-day rolling average).
1.1E–03 lb per MMBtu of heat input;
or (2.3E–05 lb per MMBtu of heat
input).
140 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (150 ppm by volume on a dry basis corrected to 3
percent oxygen, 30-day rolling average).
1.1E–03 lb per MMBtu of heat input;
or (2.3E–05 lb per MMBtu of heat
input).
620 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (410 ppm by volume on a dry basis corrected to 3
percent oxygen, 10-day rolling average).
3.0E–02 lb per MMBtu of heat input;
or (2.6E–05 lb per MMBtu of heat
input).
460 ppm by volume on a dry basis
corrected to 3 percent oxygen.
2. Pulverized coal boilers designed to
burn coal/solid fossil fuel.
b. Filterable PM (or
TSM).
3. Stokers designed to burn coal/solid
fossil fuel.
a. CO (or CEMS) .......
b. Filterable PM (or
TSM).
4. Fluidized bed units designed to
burn coal/solid fossil fuel.
a. CO (or CEMS) .......
b. Filterable PM (or
TSM).
5. Fluidized bed units with an integrated heat exchanger designed to
burn coal/solid fossil fuel.
a. CO (or CEMS) .......
b. Filterable PM (or
TSM).
6.
Stokers/sloped grate/others designed to burn wet biomass fuel.
a. CO (or CEMS) .......
b. Filterable PM (or
TSM).
7.
Stokers/sloped grate/others designed to burn kiln-dried biomass
fuel.
a. CO .........................
tkelley on DSK3SPTVN1PROD with
b. Filterable PM (or
TSM).
8. Fluidized bed units designed to
burn biomass/bio-based solids.
VerDate Mar<15>2010
18:47 Jan 30, 2013
a. CO (or CEMS) .......
Jkt 229001
PO 00000
Frm 00075
3.2E–01 lb per MMBtu of heat input;
or (4.0E–03 lb per MMBtu of heat
input).
230 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (310 ppm by volume on a dry basis corrected to 3
percent oxygen, 30-day rolling average).
Fmt 4701
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E:\FR\FM\31JAR3.SGM
Using this specified sampling volume
or test run duration . . .
For M26A, collect a minimum of 1
dscm per run; for M26 collect a
minimum of 120 liters per run.
For M29, collect a minimum of 4 dscm
per run; for M30A or M30B, collect
a minimum sample as specified in
the method; for ASTM D6784 b collect a minimum of 4 dscm.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
31JAR3
7212
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
TABLE 13 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS
AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER DECEMBER 23, 2011, AND
BEFORE JANUARY 31, 2013—Continued
If your boiler or process heater is in
this subcategory . . .
For the following pollutants . . .
b. Filterable PM (or
TSM).
The emissions must not exceed the
following emission limits, except during periods of startup and shutdown
. . .
a. HCl ........................
b. Mercury .................
9. Suspension burners designed to
burn biomass/bio-based solids.
9.8E–03 lb per MMBtu of heat input;
or (8.3E–05 a lb per MMBtu of heat
input).
2,400 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (2,000 ppm by volume on a dry basis corrected to 3
percent oxygen, 10-day rolling average).
5.1E–02 lb per MMBtu of heat input;
or (6.5E–03 lb per MMBtu of heat
input).
810 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (520 ppm by volume on a dry basis corrected to 3
percent oxygen, 10-day rolling average).
3.6E–02 lb per MMBtu of heat input;
or (3.9E–05 lb per MMBtu of heat
input).
910 ppm by volume on a dry basis
corrected to 3 percent oxygen.
2.0E–02 lb per MMBtu of heat input;
or (2.9E–05 lb per MMBtu of heat
input).
1,500 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (900 ppm by volume on a dry basis corrected to 3
percent oxygen, 30-day rolling average).
2.6E–02 lb per MMBtu of heat input;
or (4.4E–04 lb per MMBtu of heat
input).
1.2E–03 lb per MMBtu of heat input ...
4.9E–07 a lb per MMBtu of heat input
a. CO (or CEMS) .......
130 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average; or (18 ppm by volume
on a dry basis corrected to 3 percent oxygen, 10-day rolling average).
1.3E–03 lb per MMBtu of heat input;
or (7.5E–05 lb per MMBtu of heat
input).
130 a ppm by volume on a dry basis
corrected to 3 percent oxygen; or
(60 ppm by volume on a dry basis
corrected to 3 percent oxygen, 1day block average)..
1.1E–03 a lb per MMBtu of heat input;
or (2.9E–05 lb per MMBtu of heat
input).
130 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3run average based on stack test; or
(91 ppm by volume on a dry basis
corrected to 3 percent oxygen, 3hour rolling average).
a. CO (or CEMS) .......
b. Filterable PM (or
TSM).
10. Dutch Ovens/Pile burners designed to burn biomass/bio-based
solids.
a. CO (or CEMS) .......
b. Filterable PM (or
TSM).
11. Fuel cell units designed to burn
biomass/bio-based solids.
a. CO .........................
b. Filterable PM (or
TSM).
12. Hybrid suspension grate boiler designed to burn biomass/bio-based
solids.
a. CO (or CEMS) .......
b. Filterable PM (or
TSM).
13. Units designed to burn liquid fuel ..
14. Units designed to burn heavy liquid fuel.
b. Filterable PM (or
TSM).
15. Units designed to burn light liquid
fuel.
a. CO (or CEMS) .......
tkelley on DSK3SPTVN1PROD with
b. Filterable PM (or
TSM).
16. Units designed to burn liquid fuel
that are non-continental units.
VerDate Mar<15>2010
18:47 Jan 30, 2013
a. CO .........................
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Using this specified sampling volume
or test run duration . . .
Collect a minimum of 3 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run.
For M26A: Collect a minimum of 2
dscm per run; for M26, collect a
minimum of 240 liters per run.
For M29, collect a minimum of 4 dscm
per run; for M30A or M30B, collect
a minimum sample as specified in
the method; for ASTM D6784 b collect a minimum of 4 dscm.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run.
1 hr minimum sampling time.
Collect a minimum of 3 dscm per run.
1 hr minimum sampling time.
31JAR3
Federal Register / Vol. 78, No. 21 / Thursday, January 31, 2013 / Rules and Regulations
7213
TABLE 13 TO SUBPART DDDDD OF PART 63—ALTERNATIVE EMISSION LIMITS FOR NEW OR RECONSTRUCTED BOILERS
AND PROCESS HEATERS THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER DECEMBER 23, 2011, AND
BEFORE JANUARY 31, 2013—Continued
If your boiler or process heater is in
this subcategory . . .
For the following pollutants . . .
b. Filterable PM (or
TSM).
The emissions must not exceed the
following emission limits, except during periods of startup and shutdown
. . .
b. HCl ........................
c. Mercury ..................
7.9E–06 lb per MMBtu of heat input ...
d. Filterable PM (or
TSM).
17. Units designed to burn gas 2
(other) gases.
2.3E–02 lb per MMBtu of heat input;
or (8.6E–04 lb per MMBtu of heat
input).
130 ppm by volume on a dry basis
corrected to 3 percent oxygen.
1.7E–03 lb per MMBtu of heat input ...
6.7E–03 lb per MMBtu of heat input;
or (2.1E–04 lb per MMBtu of heat
input).
a. CO .........................
Using this specified sampling volume
or test run duration . . .
Collect a minimum of 2 dscm per run.
1 hr minimum sampling time.
For M26A, Collect a minimum of 2
dscm per run; for M26, collect a
minimum of 240 liters per run.
For M29, collect a minimum of 3 dscm
per run; for M30A or M30B, collect
a minimum sample as specified in
the method; for ASTM D6784 b collect a minimum of 3 dscm.
Collect a minimum of 3 dscm per run.
a If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant for at least 2 consecutive years
show that your emissions are at or below this limit and you are not required to conduct testing for CEMS or CPMS monitor certification, you can
skip testing according to § 63.7515 if all of the other provision of § 63.7515 are met. For all other pollutants that do not contain a footnote ‘‘a’’,
your performance tests for this pollutant for at least 2 consecutive years must show that your emissions are at or below 75 percent of this limit in
order to qualify for skip testing.
b Incorporated by reference, see § 63.14.
[FR Doc. 2012–31646 Filed 1–30–13; 8:45 am]
tkelley on DSK3SPTVN1PROD with
BILLING CODE 6560–50–P
VerDate Mar<15>2010
18:47 Jan 30, 2013
Jkt 229001
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31JAR3
]]>Agencies
[Federal Register Volume 78, Number 21 (Thursday, January 31, 2013)]
[Rules and Regulations]
[Pages 7137-7213]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-31646]
[[Page 7137]]
Vol. 78
Thursday,
No. 21
January 31, 2013
Part V
Environmental Protection Agency
-----------------------------------------------------------------------
40 CFR Part 63
National Emission Standards for Hazardous Air Pollutants for Major
Sources: Industrial, Commercial, and Institutional Boilers and Process
Heaters; Final Rule
Federal Register / Vol. 78 , No. 21 / Thursday, January 31, 2013 /
Rules and Regulations
[[Page 7138]]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 63
[EPA-HQ-OAR-2002-0058; FRL-9676-8]
RIN 2060-AR13
National Emission Standards for Hazardous Air Pollutants for
Major Sources: Industrial, Commercial, and Institutional Boilers and
Process Heaters
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule; notice of final action on reconsideration.
-----------------------------------------------------------------------
SUMMARY: In this action the EPA is taking final action on its
reconsideration of certain issues in the emission standards for the
control of hazardous air pollutants from new and existing industrial,
commercial, and institutional boilers and process heaters at major
sources of hazardous air pollutants, which were issued under section
112 of the Clean Air Act. As part of this action, the EPA is making
technical corrections to the final rule to clarify definitions,
references, applicability and compliance issues raised by petitioners
and other stakeholders affected by this rule. On March 21, 2011, the
EPA promulgated national emission standards for this source category.
On that same day, the EPA also published a notice announcing its intent
to reconsider certain provisions of the final rule. Following these
actions, the Administrator received several petitions for
reconsideration. After consideration of the petitions received, on
December 23, 2011, the EPA proposed revisions to certain provisions of
the March 21, 2011, final rule, and requested public comment on several
provisions of the final rule. The EPA is now taking final action on the
proposed reconsideration.
DATES: The May 18, 2011 (76 FR28661), delay of the effective date
revising subpart DDDDD at 76 FR 15451 (March 21, 2011) is lifted
January 31, 2013. The amendments in this rule to 40 CFR part 63,
subpart DDDDD are effective as of April 1, 2013.
ADDRESSES: The EPA established a single docket under Docket ID No. EPA-
HQ-OAR-2002-0058 for this action. All documents in the docket are
listed on the https://www.regulations.gov Web site. Although listed in
the index, some information is not publicly available, e.g.,
confidential business information or other information whose disclosure
is restricted by statute. Certain other material, such as copyrighted
material, is not placed on the Internet and will be publicly available
only in hard copy form. Publicly available docket materials are
available either electronically through https://www.regulations.gov or
in hard copy at the EPA's Docket Center, Public Reading Room, EPA West
Building, Room 3334, 1301 Constitution Avenue NW., Washington, DC
20004. This Docket Facility is open from 8:30 a.m. to 4:30 p.m., Monday
through Friday, excluding legal holidays. The telephone number for the
Public Reading Room is (202) 566-1744, and the telephone number for the
Air Docket is (202) 566-1742.
FOR FURTHER INFORMATION CONTACT: Mr. Jim Eddinger, Energy Strategies
Group, Sector Policies and Programs Division, (D243-01), Office of Air
Quality Planning and Standards, U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina 27711; Telephone number: (919)
541-5426; Fax number (919) 541-5450; Email address:
eddinger.jim@epa.gov.
SUPPLEMENTARY INFORMATION:
Executive Summary
Purpose of This Regulatory Action
The EPA is taking final action on its proposed reconsideration of
certain provisions of its March 21, 2011, final rule that established
standards for new and existing industrial, commercial, and
institutional boilers and process heaters at major sources of hazardous
air pollutants. Section 112(d) of the CAA requires the EPA to regulate
HAP from major stationary sources based on the performance of MACT.
Section 112(h) of the CAA allows the EPA to establish work practice
standards in lieu of numerical emission limits only in cases where the
agency determines that it is not feasible to prescribe or enforce an
emission standard, including circumstances in which the agency
determines that the application of measurement methodology is not
practicable due to technological and economic limitations. The EPA is
revising certain MACT standards established in March 2011 for boilers
and process heaters, including standards for CO--as a surrogate for
organic HAP; HCl--as a surrogate for acid gas HAP; Hg; TSM or
filterable PM--as a surrogate for non-Hg metallic HAP; and dioxin/
furan.
This final rule amends certain provisions of the final rule issued
by the EPA on March 21, 2011. The EPA delayed the effective date of the
2011 rule in a May 18, 2011, notice, but that delay notice was vacated
by the U.S. District Court for the District of Columbia on January 9,
2012, and the March 2011 final rule was, therefore, in effect until
publication of this action.
Summary of Major Reconsideration Provisions
In general, this final rule requires facilities classified as major
sources of HAP with affected boilers or process heaters to reduce
emissions of harmful toxic air emissions from these combustion sources.
This will improve air quality and protect public health in communities
where these facilities are located.
Recognizing the diversity of this source category and the multiple
sectors of the economy this final rule effects, the EPA is revising
certain subcategories for boilers and process heaters in this action
that were established in the March 2011 final rule, based on the design
of the combustion equipment. These revisions result in 19 subcategories
for the boilers and process heaters source category. Numerical emission
limits are established for most of the subcategories for five
pollutants, CO, HCl, Hg, and PM or TSM. The review of existing data and
consideration of new data have resulted in changes to some of the
emission limits contained in the March 2011 final rule. Overall, for
both new and existing affected units, about 30 percent of the emission
limits are more stringent, half are less stringent, and 20 percent
unchanged as compared to the March 2011 final rule. Also, based on its
review and analysis of new data submissions, the EPA is establishing an
alternative emission standard for CO, based on CEMS data for several
subcategories with CO CEMS data available. This alternative standard is
based on a 30-day rolling average for subcategories for which
sufficient CEMS data were available for more than a 30-day period, or a
10-day rolling average for subcategories for which CEMS data were
available for less than a 30-day period, and provides additional
compliance flexibility to sources. All of the subcategories are subject
to periodic tune-up work practices for dioxin/furan emissions.
The compliance dates for the rule are January 31, 2016, for
existing sources and, January 31, 2013, or upon startup, whichever is
later, for new sources. New sources are defined as sources that began
operation on or after June 4, 2010.
Costs and Benefits
The final rule affects 1,700 existing major source facilities with
an estimated 14,136 boilers and process heaters and the EPA projects an
additional 1,844 new boilers and process heaters to be subject to this
final rule over the next 3
[[Page 7139]]
years. This final rule affects multiple sectors of the economy
including small entities. Table 1 summarizes the costs and benefits
associated with this final rule. A more detailed discussion of the
costs and benefits of this final rule is provided in section VI of this
preamble.
Table 1--Summary of the Monetized Benefits, Social Costs and Net Benefits for the Final Boiler MACT
Reconsideration in 2015
[Millions of 2008$] \1\
----------------------------------------------------------------------------------------------------------------
3 percent discount rate 7 percent discount rate
----------------------------------------------------------------------------------------------------------------
Total Monetized Benefits \2\.......... $27,000 to $67,000................. $25,000 to $61,000.
Total Social Costs \3\................ $1,400 to $1,600................... $1,400 to $1,600.
Net Benefits.......................... $26,000 to $65,000................. $23,000 to $59,000.
----------------------------------------------------------------------------------------------------------------
Non-monetized Benefits................ Health effects from exposure to HAP (39,000 tons of HCl, 500 tons of HF,
3,100 to 5,300 pounds of Hg and 2,500 tons of other metals).
Health effects from exposure to other criteria pollutants (180,000 tons
of CO and 572,000 tons of SO2).
Ecosystem effects.
Visibility impairment.
----------------------------------------------------------------------------------------------------------------
\1\ All estimates are for the implementation year (2015), and are rounded to two significant figures.
\2\ The total monetized co-benefits reflect the human health benefits associated with reducing exposure to PM2.5
through reductions of PM2.5 precursors such as directly emitted particles, SO2, and NOX and reducing exposure
to ozone through reductions of VOC. It is important to note that the monetized benefits include many but not
all health effects associated with PM2.5 exposure. Monetized benefits are shown as a range from Pope et al.
(2002) to Laden et al. (2006). These models assume that all fine particles, regardless of their chemical
composition, are equally potent in causing premature mortality because the scientific evidence is not yet
sufficient to support the development of differential effects estimates by particle type. These estimates
include the energy disbenefits valued at $24 million (using the 3 percent discount rate), which do not change
the rounded totals. CO2-related disbenefits were calculated using the ``social cost of carbon,'' which is
discussed further in the RIA.
\3\ The methodology used to estimate social costs for one year in the multimarket model using surplus changes
results in the same social costs for both discount rates.
Acronyms and Abbreviations. The following acronyms and
abbreviations are used in this document.
ACC American Chemistry Council
ACCCI American Coke and Coal Chemicals Institute
AF&PA American Forest and Paper Association
AHFA American Home Furnishings Alliance
AISI American Iron and Steel Institute
AMP American Municipal Power Inc.
AIE Alliance for Industrial Efficiency
APCD air pollution control devices
API American Petroleum Institute
AIF Auto Industry Forum
BFG Blast furnace gas
BLDS Bag leak detection system
BCSE The Business Council for Sustainable Energy
CIBO Council of Industrial Boiler Owners
CO Carbon monoxide
CO2 Carbon dioxide
CEMS Continuous emissions monitoring system
CEG Citizens Energy Group
CAA Clean Air Act
CFR Code of Federal Regulations
CPMS Continuous parameter monitoring system
CMI CraftMaster Manufacturing Inc.
ERT Electronic Reporting Tool
ESP Electrostatic precipitator
EPA Environmental Protection Agency
FBC Fluidized bed combustion
FR Federal Register
FSI Florida Sugar Industry
GPSP Great Plains Synfuels Plant
HAP Hazardous air pollutants
HBES Health-based emissions standard
HF Hydrogen fluoride
Hg Mercury
HCl Hydrogen chloride
kWh Kilowatt hours
ISO International Standards Organization
lb Pounds
LFG Landfill gas
MACT Maximum achievable control technology
MATS Mercury Air Toxics Standards
MSU Michigan State University
MMBtu Million British thermal units
NESHAP National Emission Standards for Hazardous Air Pollutants
NPRA National Petrochemical and Refiners Association
NTTAA National Technology Transfer and Advancement Act
NAICS North American Industry Classification System
NOX Nitrogen oxide
NSR New Source Review
OMB Office of Management and Budget
PM Particulate matter
PSU Penn State University
PS Performance Specification
ppm Parts per million
QA Quality assurance
QC Quality control
RFA Regulatory Flexibility Act
RIA Regulatory Impact Analysis
RPU Rochester Public Utilities
RTC Response to comment
SCR Selective catalytic reduction
SNCR Selective non-catalytic reduction
SO2 Sulfur dioxide
TBtu/yr Trillion British thermal units per year
THC Total hydrocarbon
TSM Total selected metals
TTN Technology Transfer Network
tpy Tons per year
UMRA Unfunded Mandates Reform Act of 1995
U.S. United States
USCHPA US Clean Heat Power Association
US Sugar United States Sugar Corporation
UPL Upper prediction limit
UARG Utility Air Regulatory Group
VCS Voluntary Consensus Standards
VOC Volatile organic compounds
WM Waste Management Inc.
WEPCO Wisconsin Electric Power Company
WWW Worldwide Web
Organization of this Document. The information presented in this
preamble is organized as follows:
I. General Information
A. Does this action apply to me?
B. Where can I get a copy of this document?
C. Judicial Review
II. Background Information
A. Chronological History of Related Actions
III. Summary of This Final Rule
A. What is an affected source?
B. What are the subcategories of boilers and process heaters?
C. What emission limits and work practice standards are being
finalized?
D. What are the requirements during periods of startup and
shutdown?
E. What are the testing and initial compliance requirements?
F. What are the continuous compliance requirements?
[[Page 7140]]
G. What are the compliance dates?
IV. Summary of Significant Changes Since Proposal
A. Applicability
B. Subcategories
C. Performance Test Requirements
D. Emission Limits
E. Work Practice Requirement
F. Averaging Times Definitions
G. Energy Assessment
H. Startup and Shutdown Definitions
I. Fuel Sampling Frequency
J. Affirmative Defense
V. Other Actions We Are Taking
VI. Impacts of This Final Rule
A. What are the incremental air impacts?
B. What are the incremental water and solid waste impacts?
C. What are the incremental energy impacts?
D. What are the incremental cost impacts?
E. What are the economic impacts?
F. What are the benefits of this final rule?
G. What are the incremental secondary air impacts?
VII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act
D. Unfunded Mandates Reform Act
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination with
Indian Tribal Governments
G. Executive Order 13045: Protection of Children from
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. Executive Order 12898: Federal Actions to Address
Environmental Justice in Minority Populations and Low-Income
Populations
K. Congressional Review Act
I. General Information
A. Does this action apply to me?
The regulated categories and entities potentially affected by this
action include:
TABLE 2--Potential Regulated Categories and Entities Affected
----------------------------------------------------------------------------------------------------------------
Category NAICS code\1\ Examples of potentially regulated entities
----------------------------------------------------------------------------------------------------------------
Any industry using a boiler or 211 Extractors of crude petroleum and natural gas.
process heater as defined in the
final rule.
321 Manufacturers of lumber and wood products.
322 Pulp and paper mills.
325 Chemical manufacturers.
324 Petroleum refineries, and manufacturers of coal
products.
316, 326, Manufacturers of rubber and miscellaneous plastic
339 products.
331 Steel works, blast furnaces.
332 Electroplating, plating, polishing, anodizing, and
coloring.
336 Manufacturers of motor vehicle parts and accessories.
221 Electric, gas, and sanitary services.
622 Health services.
611 Educational services.
----------------------------------------------------------------------------------------------------------------
\1\ North American Industry Classification System.
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
reconsideration action. To determine whether your facility may be
affected by this reconsideration action, you should examine the
applicability criteria in 40 CFR 63.7485 of subpart DDDDD (National
Emission Standards for Hazardous Air Pollutants (NESHAP) for
Industrial, Commercial, and Institutional Boilers and Process Heaters).
If you have any questions regarding the applicability of this final
rule to a particular entity, consult either the air permitting
authority for the entity or your EPA regional representative, as listed
in 40 CFR 63.13 of subpart A (General Provisions).
B. Where can I get a copy of this document?
In addition to being available in the docket, an electronic copy of
this action will also be available on the WWW through the TTN.
Following signature, a copy of the action will be posted on the TTN's
policy and guidance page for newly proposed or promulgated rules at the
following address: https://www.epa.gov/ttn/oarpg/. The TTN provides
information and technology exchange in various areas of air pollution
control.
C. Judicial Review
Under the CAA section 307(b)(1), judicial review of this final rule
is available only by filing a petition for review in the U.S. Court of
Appeals for the District of Columbia Circuit by April 1, 2013. Under
CAA section 307(d)(7)(B), only an objection to this final rule that was
raised with reasonable specificity during the period for public comment
can be raised during judicial review. Note, under CAA section
307(b)(2), the requirements established by this final rule may not be
challenged separately in any civil or criminal proceedings brought by
the EPA to enforce these requirements.
II. Background Information
A. Chronological History of Related Actions
On March 21, 2011, the EPA issued final standards for new and
existing industrial, commercial, and institutional boilers and process
heaters, pursuant to its authority under section 112 of the CAA. On the
same day as the final rule was issued, the EPA stated in a separate
notice that it planned to initiate a reconsideration of several
provisions of the final rule. This reconsideration notice identified
several provisions of the March 2011 final rule where additional public
comment was appropriate. This notice also identified several issues of
central relevance to the rulemaking where reconsideration was
appropriate under CAA section 307(d).
On May 18, 2011, the EPA issued a notice to postpone the effective
date of the March 21, 2011 final rule. Following promulgation of the
final rule, the EPA received petitions for reconsideration from the
following organizations
[[Page 7141]]
(``Petitioners''): AIE, USCHPA, Alyeska Pipeline, ACC, AHFA, AISI,
ACCCI, AMP, API, NPRA, AIF, Citizens Energy Group (CEG), CIBO, CMI,
District Energy St. Paul, FSI, GPSP, Hovensa L.L.C., Tesoro Hawaii
Corp., Industry Coalition (AF&PA et al.), JELD-WEN Inc., MSU, PSU,
Purdue University, Renovar Energy Corp., RPU, Sierra Club, Southeastern
Lumber Manufacturers Association, State of Washington Department of
Ecology, BCSE, UARG, US Sugar, WM and WEPCO. Copies of these petitions
are provided in the docket (see Docket ID No. EPA-HQ-OAR-2002-0058).
Petitioners, pursuant to CAA section 307(d)(7)(B), requested that the
EPA reconsider numerous provisions in the rule. On December 23, 2011,
the EPA granted the petitions for reconsideration on certain issues,
and proposed certain revisions to the final rule in response to the
reconsideration petitions and to address the issues that the EPA
previously identified as warranting reconsideration. That proposal
solicited comment on several specific aspects of the rule, including:
Revising the proposed subcategories.
Solicitation of new data or corrections to existing data
to revise emission standards calculations.
Establishing an alternative TSM limit.
Appropriateness of an alternative TSM limit for the liquid
subcategories.
Establishing work practice standards for dioxin/furan
emissions.
Revising the efficiency assumptions for the alternative
output-based emission standards.
Accommodating emissions averaging provisions in the
alternative output-based emission standards.
Establishing a mercury fuel specification through which
gas-fired boilers that use a fuel other than natural gas or refinery
gas may be considered Gas 1 units.
Establishing a work practice standard for limited use
units.
Providing an affirmative defense for malfunction events.
Revisions to the monitoring requirements for oxygen in the
March 2011 final rule.
Establishing a full-load stack test requirement for carbon
monoxide coupled with continuous oxygen (oxygen trim) monitoring.
Revising PM monitoring requirements from CEMS to CPMS and
exempting biomass units from PM CPMS requirements.
Revising mercury monitoring requirements to allow for an
alternative mercury CEMS.
Considering use of SO2 CEMS to demonstrate
compliance with HCl limits.
Minimum data availability provisions.
Averaging times for monitored parameters and pollutants.
Revised methods for computing minimum detection levels.
Providing an alternative CO emission limit based on CO
CEMS data.
Soliciting additional data to set MACT floor emission
limits for non-continental liquid units.
Selecting a 99 percent confidence interval for setting the
CO emission limit.
Tune-up frequencies, timing of initial tune-ups and
adjusted tune-up requirements for shutdown units.
Scope and duration of the energy assessment and deadline
for completing the assessment.
Revising work practices during startup and shutdown.
Revisions to certain exemptions, including units serving
as control devices, waste heat process heaters, units firing comparable
fuels and residential units.
Revisions to reduced testing frequency for emission limits
that are established at minimum detection levels.
Removing fuel analysis requirements for gas 1 fuels at co-
fired units.
Revisions to automating techniques for coal sampling.
Revisions to emissions averaging across subcategories when
units opt to switch to natural gas.
Consideration of a new subcategory for units installed and
used in place of flares.
In this action, the EPA is finalizing multiple changes to the March
2011 final rule after considering public comments on the items under
reconsideration.
III. Summary of This Final Rule
As stated above, the December 23, 2011 proposed rule addressed
specific issues and provisions the EPA identified for reconsideration.
This summary of the final rule reflects the changes to 40 CFR part 63,
subpart DDDDD (March 21, 2011 final rule) in regards to those
provisions identified for reconsideration and on other discrete matters
identified in response to comments or data received during the comment
period. Information on other provisions and issues not proposed for
reconsideration is contained in the notice and record for the 2011
final rule. [See 76 FR 15608]
This section summarizes the requirements of this action. Section IV
below provides a summary of the significant changes to the March 21,
2011 final rule.
A. What is an affected source?
This final rule revises the list of exemptions in Sec. 63.7491 to
include residential boilers that may be located at an industrial,
commercial or institutional major source. The exemption for boilers or
process heaters used specifically for research and development has been
revised to include boilers used for certain testing purposes.
B. What are the subcategories of boilers and process heaters?
In this final rule, we are finalizing separate subcategories for
heavy liquid-fired, light liquid-fired and liquid-fired units in non-
continental locations for PM and CO, pollutants that are dependent on
combustor design. In addition, a new subcategory for coal-fired
fluidized bed boilers with integrated fluidized bed heat exchangers has
been included in the final rule for CO which is dependent on boiler
design. Finally, we are finalizing the subcategory for PM at coal/
fossil solid units across all coal combustor designs.
C. What emission limits and work practice standards are being
finalized?
You must meet the emission limits presented in Table 3 of this
preamble for each subcategory of units listed in the table. This final
rule includes 19 subcategories, which are based on unit design. New and
existing units in three of the subcategories are subject to work
practices standards in lieu of emission limits for all pollutants.
Numeric emission limits are finalized for new and existing sources in
each of the other 16 subcategories.
The changes associated with the emission limits are due to new
data, corrections to old data, and inventory changes. In summary, for
existing subcategories, for the HCl emission limits, 10 are more
stringent, 3 are less stringent and 1 remained the same from the March
21, 2011 final rule; for the mercury emission limits, 3 are more
stringent and 11 are less stringent from the March 21, 2011 final rule;
for the PM emission limits, 2 are more stringent, 7 are less stringent
and 5 are unchanged from the March 21, 2011 final rule; and for the CO
emission limits, 4 are more stringent and 10 are less stringent from
the March 21, 2011 final rule. For new subcategories, for the HCl
emission limits, 13 are less stringent and 1 is unchanged from the
March 21, 2011 final rule; for the mercury emission limits, 11 are more
[[Page 7142]]
stringent, 2 are less stringent and 1 is unchanged from the March 21,
2011 final rule; for the PM emission limits, 9 are less stringent and 5
are unchanged from the March 21, 2011 final rule; and for the CO
emission limits, 3 are more stringent and 11 are less stringent from
the March 21, 2011 final rule.
TABLE 3--Emission Limits for Boilers and Process Heaters
[lb/MMBtu heat input basis unless noted; alternative output based limits are not shown in the summary table below]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alternate CO
Filterable PM (or total HCl (lb per MMBtu of Mercury (lb per MMBtu CO (ppm @3% CEMS limit,
Subcategory selected metals) (lb per MMBtu heat input) \a\ of heat input) \a\ oxygen) \a\ (ppm @3%
of heat input) \a\ oxygen) \b\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Existing--Coal Stoker................. 0.040 (5.3E-05)................. 0.022 5.7E-06 160 340
Existing--Coal Fluidized Bed.......... 0.040 (5.3E-05)................. 0.022 5.7E-06 130 230
Existing--Coal Fluidized Bed with FB 0.040 (5.3E-05)................. 0.022 5.7E-06 140 150
heat exchanger.
Existing--Coal-Burning Pulverized Coal 0.040 (5.3E-05)................. 0.022 5.7E-06 130 320
Existing--Biomass Wet Stoker/Sloped 0.037 (2.4E-04)................. 0.022 5.7E-06 1,500 720
Grate/Other.
Existing--Biomass Kiln-Dried Stoker/ 0.32 (4.0E-03).................. 0.022 5.7E-06 460 ND
Sloped Grate/Other.
Existing--Biomass Fluidized Bed....... 0.11 (1.2E-03).................. 0.022 5.7E-06 470 310
Existing--Biomass Suspension Burner... 0.051 (6.5E-03)................. 0.022 5.7E-06 2,400 \c\ 2,000
Existing--Biomass Dutch Ovens/Pile 0.28 (2.0E-03).................. 0.022 5.7E-06 770 \c\ 520
Burners.
Existing--Biomass Fuel Cells.......... 0.020 (5.8E-03)................. 0.022 5.7E-06 1,100 ND
Existing--Biomass Hybrid Suspension 0.44(4.5E-04)................... 0.022 5.7E-06 2,800 900
Grate.
Existing--Heavy Liquid................ 0.062 (2.0E-04)................. 0.0011 2.0E-06 130 ND
Existing--Light Liquid................ 0.0079 (6.2E-05)................ 0.0011 2.0E-06 130 ND
Existing--non-Continental Liquid...... 0.27 (8.6E-04).................. 0.0011 2.0E-06 130 ND
Existing--Gas 2 (Other Process Gases). 0.0067 (2.1E-04)................ 0.0017 7.9E-06 130 ND
New--Coal Stoker...................... 0.0011 (2.3E-05)................ 0.022 8.0E-07 130 340
New--Coal Fluidized Bed............... 0.0011 (2.3E-05)................ 0.022 8.0E-07 130 230
New--Coal Fluidized Bed with FB Heat 0.0011 (2.3E-05)................ 0.022 8.0E-07 140 150
Exchanger.
New--Coal-Burning Pulverized Coal..... 0.0011 (2.3E-05)................ 0.022 8.0E-07 130 320
New--Biomass Wet Stoker/Sloped Grate/ 0.030 (2.6E-05)................. 0.022 8.0E-07 620 390
Other.
New--Biomass Kiln-Dried Stoker/Sloped 0.030 (4.0E-03)................. 0.022 8.0E-07 460 ND
Grate/Other.
New--Biomass Fluidized Bed............ 0.0098 (8.3E-05)................ 0.022 8.0E-07 230 310
New--Biomass Suspension Burner........ 0.030 (6.5E-03)................. 0.022 8.0E-07 2,400 \c\ 2,000
New--Biomass Dutch Ovens/Pile Burners. 0.0032 (3.9E-05)................ 0.022 8.0E-07 330 \c\ 520
New--Biomass Fuel Cells............... 0.020 (2.9E-05)................. 0.022 8.0E-07 910 ND
New--Biomass Hybrid Suspension Grate.. 0.026 (4.4E-04)................. 0.022 8.0E-07 1,100 900
New--Heavy Liquid..................... 0.013 (7.5E-05)................. 4.4E-04 4.8E-07 130 ND
New--Light Liquid..................... 0.0011 (2.9E-05)................ 4.4E-04 4.8E-07 130 ND
New--Non-Continental Liquid........... 0.023 (8.6E-04)................. 4.4E-04 4.8E-07 130 ND
New--Gas 2 (Other Process Gases)...... 0.0067 (2.1E-04)................ 0.0017 7.9E-06 130 ND
--------------------------------------------------------------------------------------------------------------------------------------------------------
NA-Not applicable; ND-No data available
\a\ 3-run average, unless otherwise noted.
\b\ 30-day rolling average, unless otherwise noted.
\c\ 10-day rolling average.
We also are finalizing a work practice standard for dioxin/furan
emissions from all subcategories.
D. What are the requirements during periods of startup and shutdown?
We are finalizing revised work practice standards for periods of
startup and shutdown to better reflect the maximum achievable control
technology during those periods. In addition, we are finalizing
definitions of startup and shutdown. We are defining startup as the
period between the state of first-firing of fuel in the unit after a
shutdown to the period where the unit first supplies steam. We are
defining shutdown as the period that begins when no more steam is
supplied or at the point of no fuel being fired in the unit. For
periods of startup and shutdown, we are finalizing the following work
practice standard: You must operate all continuous monitoring systems
during startup and shutdown. For startup, you must use one or a
combination of the listed clean fuels. Once you start firing coal/solid
fossil fuel, biomass/bio-based solids, heavy liquid fuel, or gas 2
(other) gases, you must engage all of the applicable control devices
except limestone injection in FBC boilers, dry scrubber, fabric filter,
SNCR and SCR. You must start your limestone injection in FBC boilers,
dry scrubber, fabric filter, SNCR and SCR systems as expeditiously as
possible. During shutdown while firing coal/solid fossil fuel, biomass/
bio-based solids, heavy liquid fuel, or gas 2 (other) gases during
shutdown, you must operate all applicable control devices, except
limestone injection in FBC boilers, dry scrubber, fabric filter, SNCR
and SCR. You must comply with all applicable emissions and operating
limits at all times the unit is in operation except for periods that
meet the definitions of startup and shutdown in this subpart, during
which times you must comply with these work practices. You must keep
records during periods of startup or shutdown. You must keep records
concerning the date, duration, and fuel usage during startup and
shutdown.
E. What are the testing and initial compliance requirements?
We are requiring that the owner or operator of a new or existing
boiler or process heater conduct performance tests to demonstrate
compliance with all applicable emission limits. This final rule adds
the requirement to conduct initial and annual stack tests to determine
compliance with the TSM emission limits using EPA Method 29 for those
subcategories with alternate TSM limits.
[[Page 7143]]
F. What are the continuous compliance requirements?
This final rule removes the requirement for units combusting
biomass with heat input capacities of 250 MMBtu/hr or greater to
install, certify, maintain and operate a CEMS measuring PM emissions.
This final rule requires units combusting solid fossil fuel or heavy
liquid with heat input capacities of 250 MMBtu/hr or greater to
install, certify, maintain, and operate PM CPMS. Moreover, owners or
operators of units combusting solid fossil fuel or heavy liquid with
heat input capacities of 250 MMBtu/hr or greater are allowed to
install, certify, maintain and operate PM CEMS as an alternative to the
use of PM CPMS, consistent with regulations for similarly-sized
commercial and industrial solid waste incinerators units and EGUs
subject to the MATS. Just as units using PM CPMS will not be required
to conduct parameter monitoring for PM, units using PM CEMS will not be
required to conduct parameter monitoring for PM.
This final rule also includes an alternative method of
demonstrating continuous compliance with the HCl emission limit. This
method allows using SO2 emissions as an alternate operating
limit. This method of demonstrating continuous compliance will be
allowed only on a unit that utilizes a SO2 CEMS and an acid-
gas control technology including wet scrubber, dry scrubbers and duct
sorbent injection. Boilers or process heaters subject to an HCl
emission limit that demonstrate compliance with an SO2 CEMS
would be required to maintain the 30-day rolling average SO2
emission rate at or below the highest hourly average SO2
concentration measured during the most recent HCl performance test.
G. What are the compliance dates?
For existing sources, the EPA is establishing a compliance date of
January 31, 2016. New sources must comply by January 31, 2013, or upon
startup, whichever is later. New sources are defined as sources which
commenced construction or reconstruction on or after June 4, 2010
pursuant to section 112(a)(4).
Commenters have argued that the 3-year compliance deadline the EPA
is establishing for existing sources to meet the standards does not
provide them with sufficient time to meet the standards in view of the
large number of sources that will be competing for the needed resources
and materials from engineering consultants, permitting authorities,
equipment vendors, construction contractors, financial institutions,
and other critical suppliers.
As an initial matter, we note that many sources subject to the
emission standards in the final rule should be able to meet the
standards within three years, even those that need to install pollution
control technologies to do so. In addition, many sources subject to the
rule are gas fired units or small boilers (less than 10 MMBtu/hr) and
will not need to install controls in order to demonstrate compliance,
as these sources are subject to work practice standards. For these
sources, the 3-year compliance deadline is highly unlikely to be
problematic either in general, or with respect to the claims commenters
have made about the possibility that the demand for resources related
to control technology will exceed the supply.
At the same time, the CAA allows title V permitting authorities to
grant sources, on a case-by-case basis, extensions to the compliance
time of up to one year if such time is needed for the installation of
controls. See CAA section 112(i)(4)(i)(A). Permitting authorities are
already familiar with, and in many cases have experience with, applying
the 1-year extension authority under section 112(i)(4)(A) since the
provision applies to all NESHAP. We believe that should the range of
circumstances that commenters have cited as impeding sources' ability
to install controls within three years materialize, then it is
reasonable for permitting authorities to take those circumstances into
consideration when evaluating a source's request for a 1-year
extension, and where such applications prove to be well-founded, it is
also reasonable for permitting authorities to make the 1-year extension
available to applicants.
In making a determination as to whether an extension is
appropriate, we believe it is also reasonable for permitting
authorities to consider the large number of pollution control retrofit
projects being undertaken for purposes of complying either with the
standards in this rule or with those of other rules such as MATS for
the power sector that may be competing for similar resources.
Further, commenters have pointed out that in some cases operators
of existing sources that are subject to these standards and that
generate energy may opt to meet the standards by terminating operations
at these sources and building new sources to replace the energy
generation at the shut-down sources. While the ultimate discretion to
provide a 1-year extension lies with the permitting authority, the EPA
believes that it is reasonable for permitting authorities to allow the
fourth year extension for the installation of replacement sources of
energy generation at the site of a facility applying for an extension
for that purpose. Specifically, the EPA believes where an applicant
demonstrates that it is building replacement sources of energy
generation for purposes of meeting the requirements of these standards
such a replacement project could be deemed to constitute the
``installation of controls'' under section 112(i)(3)(B).
In a case where pollution controls are being installed or onsite
replacement energy generation is being constructed to allow for
retirement of older, under-controlled energy generation units, a
determination that an extra year is necessary for compliance should be
relatively straightforward. In order to install controls, companies are
likely to undertake a number of steps relatively soon after the
effective date of the rule, including obtaining necessary building and
environmental permits and hiring contractors to perform the
construction of the emission controls or replacement energy generation
units. This should provide sufficient information for a permitting
authority to determine that emission controls are being installed or
that replacement energy generation is being constructed. As a result, a
permitting authority will be in a position to make a determination as
to whether a source's compliance schedule will exceed 3 years and to
quickly make a determination as to when an extension is appropriate.
In sum, the EPA believes that although most, if not all, units will
be able to fully comply with the standards within 3 years, the fourth
year that permitting authorities are allowed to grant for installation
of controls is an important flexibility that will address situations
where an extra year is necessary. Of course in situations where EPA is
the permitting authority, we would also consider the above
circumstances when acting on a permit application.
IV. Summary of Significant Changes Since Proposal
The EPA has made numerous changes in this final rule from the
proposal after consideration of the public comments received. Most are
changes to clarify applicability and implementation issues raised by
the commenters. The public comments received on the proposed changes
and the responses to them can be viewed in the memorandum ``Response to
Comments for Industrial, Commercial, and Institutional Boilers
[[Page 7144]]
and Process Heaters National Emission Standards for Hazardous Air
Pollutants'' located in the docket.
A. Applicability
Since proposal, the EPA has made certain changes to the
applicability of this final rule. We have clarified that the exemption
for boilers and process heaters used for research and development
includes boilers used for testing the propulsion systems on military
vessels. This is consistent with the intent of the exemption in that
these test boilers do not provide steam for heating, to a process, or
other non-propulsion related uses but are used exclusively to test the
propulsion systems of nuclear-powered aircraft carriers that are
undergoing repair, overhaul, or installation.
B. Subcategories
As described in the preamble to the proposed reconsideration rule,
within the basic unit types of boilers and process heaters there are
different designs and combustion systems that, while having a minor
effect on fuel-dependent HAP emissions, have a much larger effect on
pollutants whose emissions depend on the combustion conditions in a
boiler or process heater. In the case of boilers and process heaters,
the combustion-related pollutants are the organic HAP. In the proposed
rule, we identified the following 17 subcategories for organic HAP: (1)
Pulverized coal units; (2) stokers designed to burn coal; (3) fluidized
bed units designed to burn coal; (4) stokers designed to burn wet
biomass; (5) stokers designed to burn kiln-dried biomass; (6) fluidized
bed units designed to burn biomass; (7) suspension burners designed to
burn biomass; (8) dutch ovens/pile burners designed to burn biomass;
(9) fuel cells designed to burn biomass; (10) hybrid suspension grate
units designed to burn biomass; (11) units designed to burn heavy
liquid fuel; (12) units designed to burn light liquid fuel; (13) non-
continental liquid units; (14) units designed to burn natural gas/
refinery gas; (15) units designed to burn other gases; (16) metal
process furnaces; and (17) limited-use units.
In this final rule, we are also adding a separate subcategory for
fluidized bed units with a fluidized bed heat exchanger designed to
burn coal and adjusted the definition of the limited use subcategory.
Fluidized bed boilers are designed to combust fuel with relatively
low heating value and high ash compared to other combustor designs. Two
fuel properties of coal are heating values and ash content. As the
heating value of the coal decreases, ash content increases. Fluidized
bed boilers are designed to have large tube surface areas to transfer
heat from the fuel through the process of conduction and convection,
but in some cases the amount of tube surface area in the furnace for
heat transfer is insufficient. In order to overcome insufficient heat
exchange, certain fluidized bed boilers adopt a fluidized bed heat
exchanger design to achieve heat transfer. The fluidized bed heat
exchanger is located at the exit of the cyclone section of the unit.
This design allows the boiler to combust coal with a lower heating
value than a coal-fired fluidized bed boiler without a fluidized bed
heat exchanger. Therefore, because this boiler design does have
different combustion-related HAP emission characteristics, a new
subcategory of coal fluidized bed with integrated heat exchanger was
added to the final rule.
The EPA is also revising the definition of the limited use
subcategory. Many affected units operate on standby mode or low loads
for periods longer than the proposed definition for limited use units,
which limited operation to 876 hours per year. By converting to a
capacity-factor approach, we are allowing more flexibility on unit
operations without increasing emissions or harm to human health and the
environment. For example, units operating at 10 percent load for 8,760
hours per year would emit the same amount of emissions as units
operating at full load for 876 hours per year. Further, it is
technically infeasible to schedule stack testing for these limited use
units since these units serve as back up energy sources and their
operating schedules can be intermittent and unpredictable. The limited
use subcategory was adjusted to be based on units with a federally
enforceable operating limit of less than or equal to 10 percent of an
average annual capacity factor.
C. Performance Test Requirements
Table 5 of this final rule has been revised to add performance test
procedures for conducting performance stack tests for demonstrating
compliance with the alternate TSM emission limits. In the
reconsideration proposal, we proposed emissions limits for TSM (i.e.,
arsenic, beryllium, cadmium, chromium, lead, manganese, nickel and
selenium) as an alternative to the proposed PM emission limits for many
of the subcategories. In the preamble to the proposed rule, we added
procedures in Table 6 of the rule for conducting fuel analysis for
total selected metals but we inadvertently failed to add performance
test requirements for stack sampling of TSM emissions in Table 5 of the
rule.
D. Emission Limits
One significant change since proposal is related to the PM emission
limits for the coal subcategories. Several petitioners disagreed with
EPA's position to set different PM limits for subcategories of boilers
and process heaters based on the fuel used, and instead offered
information to support the position that PM should be considered a
combustion-based pollutant. The differences in PM particle size,
fouling characteristics and feasibility of certain control technologies
on certain unit designs suggested that PM is more appropriately
classified as a combustion-based pollutant, but only for the coal
subcategories. After assessing the points raised by the petitioners,
the EPA agreed that PM emissions are influenced by unit design, and
fuel type, and proposed to create combustion-based pollutant
subcategories for coal and solid fuels and create fuel-based
subcategories for liquid and biomass fuel units. The EPA is finalizing
a single PM limit for all coal/solid fossil fuel subcategories, and is
also finalizing emissions limits based on PM as a combustion-based
pollutant for the biomass and liquid fuel subcategories.
Another change from proposal is that the alternative TSM emission
limits are now applicable to the three liquid fuel subcategories.
Several commenters provided data and comments supporting these
alternative emission standards for non-mercury metallic HAP. After
assessing the revised data and the points made by the commenters, the
EPA agrees that the limited data available for liquid fuel units are
not unique to this subcategory. Based on the EPA agreeing with the
commenters, the EPA re-calculated the TSM emission limits for the
liquid fuel subcategories and included them in the final rule.
The CO emission limit for several subcategories, both new and
existing, have been revised to reflect a CO level that is consistent
with MACT for organic HAP reduction. Several commenters recommended
that the EPA evaluate a minimum CO standard (i.e., 100 ppm corrected to
7 percent oxygen) to serve as a lower bound surrogate for organic HAP.
Commenters also provided data and information to support such a
standard, and noted that the EPA has taken a similar approach in other
emission standards under section 112.
The EPA evaluated whether there is a minimum CO level for boilers
and
[[Page 7145]]
process heaters below which there is no further benefit in organic HAP
reduction/destruction. Specifically, we evaluated the relationship
between CO and formaldehyde using the available data obtained during
the rulemaking. Formaldehyde was selected as the basis of the organic
HAP comparison because it is the most prevalent organic HAP in the
emission database and a large number of paired tests existed for
boilers and process heaters for CO and formaldehyde. The paired data
show decreasing formaldehyde emissions with decreasing CO emissions
down to CO levels around 300 ppm, supporting the selection of CO as a
surrogate for organic HAP emissions. A slight increase in formaldehyde
emissions is observed at CO levels below around 200 ppm, suggesting a
breakdown in the CO-formaldehyde relationship at low CO levels. At
levels lower than 150 ppm, the mean levels of formaldehyde appear to
increase, as does the overall maximum value of and variability in
formaldehyde emissions. However, we are aware of no reason why CO
concentrations would continue to decrease and formaldehyde
concentrations would increase as combustion conditions improve. It is
possible that imprecise formaldehyde measurements at low concentrations
(i.e., 1-2 ppm) may account for this slight increase in formaldehyde
emissions observed at CO levels below 100 ppm corrected to 7 percent
oxygen. Based on this, we do not believe that such measurements are
sufficiently reliable to use as a basis for establishing an emissions
limit.
Therefore, based on the above analysis, we are promulgating a
minimum MACT floor level for CO of 130 ppm corrected to 3 percent
oxygen (which is equivalent to 100 ppm corrected to 7 percent oxygen).
We note this is the same approach used to establish the CO emission
limit of 100 ppm corrected to 7 percent oxygen for the Burning of
Hazardous Waste in Boilers and Industrial Furnaces rule. Additional
discussion of the rationale for this approach can be found in the
memorandum ``Revised MACT Floor Analysis (August 2012) for Industrial,
Commercial, Institutional Boilers and Process Heaters National Emission
Standards for Hazardous Air Pollutants--Major Source.''
Subcategories where the initial MACT floor 99 percent UPL
calculations for CO were less than 100 ppm corrected to 7 percent
oxygen (or equivalently 130 ppm corrected to 3 percent oxygen) are as
follows:
New and Existing Subcategories: Coal-FB, Coal-PC, Heavy
Liquid, Light Liquid, Non-Continental Liquid, Process Gas
New Subcategories: Coal-Stoker
We believe a CO level of 130 ppm corrected to 3 percent oxygen is an
appropriate minimum MACT floor level. Although some measurements show
CO levels below 130 ppm corrected to 3 percent oxygen, it is not
appropriate to establish a lower floor level because CO is a
conservative surrogate for organic HAP. In other words, organic HAP
emissions are extremely low when sources operate under the good
combustion conditions required to achieve CO levels in the range of
zero to 100 ppm. As such, lowering the CO floor below 100 ppm will not
provide reductions in organic HAP emissions. There are myriad factors
that affect combustion efficiency and, as a function of combustion
efficiency, CO emissions. As combustion conditions improve and
hydrocarbon levels decrease, the larger and easier to combust compounds
are oxidized to form smaller compounds that are, in turn, oxidized to
form CO and water. As combustion continues, CO is then oxidized to form
carbon dioxide and water. Because CO is a difficult to destroy
refractory compound (i.e., oxidation of CO to carbon dioxide is the
slowest and last step in the oxidation of hydrocarbons), it is a
conservative surrogate for destruction of hydrocarbons, including
organic HAP.
The conservative nature of CO as an indicator of good combustion
practices is supported by our data. At CO levels less than 100 ppm
corrected to 7 percent oxygen, our data indicate that there is no
apparent relationship between CO and organic HAP (i.e., formaldehyde).
For example, a source with a CO level of 20 ppm may have the same
measured formaldehyde as a source achieving a CO emission level of 100
ppm corrected to 7 percent oxygen. Sources are required to establish
operating requirements based on operating levels that were demonstrated
during the test. Sources must comply with these operating requirements
on a continuous basis. Compliance with these requirements adequately
assures sources will be controlling organic HAP emissions to MACT
levels.
As detailed in the docketed memorandum ``Beyond the Floor
Technology Analysis for Major Source Boilers and Process Heaters
(Revised August 2012),'' we reviewed the emission limits that are
becoming less stringent since the March 2011 final rule in order to
assess whether a beyond the floor option was technically achievable and
cost effective. As a result of this review, the PM emission limits for
several new biomass subcategories have been changed to reflect a beyond
the floor limit of 0.03 lb/MMBtu, based on the limit for new biomass
boilers in 40 CFR part 60 subparts Db and Dc. Due to the low mercury
emission limits for new solid fuel boilers, these new biomass units are
expected to install a fabric filter level of control in order to meet
the new source mercury limits for the solid fuel subcategory. This
mercury control has the co-benefit of reducing PM emissions down to
levels of 0.03 lb/MMBtu so there is no incremental cost to achieve
these additional reductions in PM for the biomass units that have a
design heat input capacity between 10 and 30 MMBtu/hr. For units with a
design heat input capacity of 30 MMBtu/hr or greater, these units are
already subject to a PM limit of 0.03 lb/MMBtu and adjusting these new
source limits to this level of control makes the limits consistent
between both rules, without adding additional costs. We did not
identify any beyond the floor options for existing source PM limits or
new and existing limits for other pollutants as technically feasible or
cost effective.
The other changes associated with the other emission limits are due
to new data, corrections to old data, and inventory changes. In
summary, compared to the December 23, 2011 proposed limits for existing
units, the final HCl emission limits remained the same; for the final
mercury emission limits, 3 are more stringent, 10 are less stringent
and 1 is unchanged; for the final PM emission limits, 3 are more
stringent, 5 are less stringent and 6 are unchanged; and for the final
CO emission limits, 3 are more stringent and 11 are less stringent. For
new units, compared to the proposed emission limits, 3 of the final HCl
emission limits are more stringent and 11 remained the same; for the
final mercury emission limits, 10 are more stringent and 4 are
unchanged; for the final PM emission limits, 5 are more stringent, 2
are less stringent and 7 are unchanged; and for the final CO emission
limits, 2 are more stringent, 11 are less stringent and 1 is unchanged.
E. Work Practice Requirement
In this final rule several changes have been made to the work
practice requirement to conduct a tune-up. First, the requirement to
inspect the burner has been revised to allow units that sell
electricity to schedule the burner inspection, as well as the air-to-
fuel system inspection, at the time of the first outage but not to
exceed 36 months from the previous inspection. This
[[Page 7146]]
change is being made to this final rule because commenters stated that
large boilers that serve electricity for sale may not require annual
outages and would, therefore, need to be taken off-line for the sole
purpose of an annual tune-up. This frequency is consistent with the
requirements of the NESHAP for electric utility boilers (40 CFR part
63, subpart UUUUU).
Also, for units where entry into a piece of process equipment or
into a storage vessel is required to complete the tune-up inspections,
inspections are required only during planned entries into the storage
vessel or into process equipment. Commenters indicated that some
process heaters are installed inside tanks and entry into the tank to
access the heater may not occur within a 5 year period.
The requirement to optimize total emissions of CO has been revised
to require that this optimization not only be consistent with the
manufacturer's specifications but also with any NOX emission
requirement to which the unit is subject. Some commenters indicated
that many boilers need different tune-up criteria due to their
requirement to also comply with low NOX emission limits. We
are also aware that several states have boiler tune-up requirements to
minimize NOX emissions first and then optimize CO emissions.
We have added boilers or process heaters that have a continuous
oxygen trim system to the types of boilers or process heaters that must
conduct a tune-up every 5 years. These units do not need to be tuned as
frequently because the trim system is designed to continuously measure
and maintain an optimum air to fuel ratio which is the purpose of a
tune-up.
F. Averaging Times Definitions
We revised the definitions of ``30-day rolling average'' and
``daily block average'' to exclude periods of startup and shutdown or
downtime from the arithmetic mean. Commenters requested that the EPA
specify how a 30-day rolling average is calculated and whether it
includes the previous 720 hours of valid operating data and that the
valid data exclude hours during startup and shutdown as well as unit
down time. We agree with the commenters that the definitions need
clarification and that these periods should not be included in
calculating the 30-day rolling average. Therefore, we have revised the
definitions accordingly.
We have also included in the final rule a definition of ``10-day
rolling average'' that is consistent with the revised definition of
``30-day rolling average.''
G. Energy Assessment
In this final rule, we have revised the definition of energy
assessment per the requirements of Table 3 of this final rule by
providing duration for performing the energy assessment for large fuel
use facilities. In numbered paragraph (3) in the definition of ``Energy
assessment'' in Sec. 63.7575, which is for facilities with units
having a combined heat input capacity greater than 1 TBtu/yr, we added
time duration/size ratio and included a cap to the maximum number of
on-site technical hours that should be used in the energy assessment.
This addition of a duration for large fuel use facilities is being made
to be consistent with durations specified for small [paragraph (1) in
the definition of ``Energy assessment''] and medium [paragraph (2) in
the definition of ``Energy assessment''] fuel use facilities. The
energy assessment for facilities with affected boilers and process
heaters having a combined heat input capacity greater than 1.0 TBtu/yr
will be up to 24 on-site technical labor hours for the first TBtu/yr
plus 8 technical labor hours for every additional 1.0 TBtu/yr not to
exceed 160 technical hours, but may be longer at the discretion of the
owner or operator.
The revised definition of energy assessment also clarifies our
intentions that the scope of assessment is based on energy use by
discrete segments of a facility and not by a total aggregation of all
individual energy using elements of a facility. The applicable discrete
segments of a facility could vary significantly depending on the site
and its complexity. We have added the following paragraph (4), to the
energy assessment definition to help resolve current problems in
identifying the scope of the various energy use systems in a large
industrial complex and allow for more streamlined assessments:
``(4) The on-site energy use systems serving as the basis for the
percent of affected boiler(s) and process heater(s) energy output in
(1), (2) and (3) above may be segmented by production area or energy
use area as most logical and applicable to the specific facility being
assessed (e.g., product X manufacturing area; product Y drying area;
Building Z).''
We have also revised paragraph 4 of Table 3 of the final rule to
allow a source that is operating under an energy management program
established through energy management systems compatible with ISO
50001, which includes the affected units, to satisfy the energy
assessment requirement. We consider these energy management programs to
be equivalent to the one-time energy assessment because facilities
having these programs operate under a set of practices and procedures
designed to manage energy use on an ongoing basis. These programs
contain energy performance measurements and tracking plans with
periodic reviews.
The definition of ``Energy use system'' has also been revised in
this final rule to clarify that energy use systems are only those
systems using energy clearly produced by affected boilers and process
heaters.
H. Startup and Shutdown Definitions
A number of commenters indicated that the proposed load
specifications (i.e., 25 percent load) within the definitions of
``startup'' and ``shutdown'' were inconsistent with either safe or
normal (proper) operation of the various types of boilers and process
heaters encountered within the source category. As the basis for
defining periods of startup and shutdown, a number of commenters
suggested alternative load specifications based on the specific
considerations of their boilers; other commenters suggested the
achievement of various steady-state conditions.
We have reviewed these comments and believe adjustments are
appropriate in the definition of ``startup'' and ``shutdown.'' These
adjustments are tailored for industrial boilers and are consistent with
the definitions of ``startup'' and ``shutdown'' contained in the 40 CFR
part 63, subpart A General Provisions. We believe these revised
definitions address the comments and are rational based on the fact
that industrial boilers function to provide steam or, in the case of
cogeneration units, electricity; therefore, industrial boilers should
be considered to be operating normally at all times steam of the proper
pressure, temperature, and flow rate is being supplied to a common
header system or energy user(s) for use as either process steam or for
the cogeneration of electricity. The definitions of ``startup'' and
``shutdown'' have been revised in the final rule as follows:
``Startup means either the first-ever firing of fuel in a boiler or
process heater for the purpose of supplying steam or heat for heating
and/or producing electricity, or for any other purpose, or the firing
of fuel in a boiler or process heater after a shutdown event for any
purpose. Startup ends when any of the steam or heat from the boiler or
process heater is supplied for heating and/or producing electricity, or
for any other purpose.''
[[Page 7147]]
``Shutdown means the cessation of operation of a boiler or process
heater for any purpose. Shutdown begins either when none of the steam
and heat from the boiler or process heater is supplied for heating and/
or producing electricity, or for any other purpose, or at the point of
no fuel being fired in the boiler or process heater, whichever is
earlier. Shutdown ends when there is both no steam or heat being
supplied and no fuel being fired in the boiler or process heater.''
The EPA is requiring sources to vent emissions to the main stack(s)
and operate all control devices necessary to meet the normal operating
standards under this final rule (with the exception of limestone
injection in FBC boilers, dry scrubber, fabric filter, SNCR and SCR)
when firing coal/solid fossil fuel, biomass/bio-based solids, heavy
liquid fuel or gas 2 (other) gases in the boiler or process heater
during startup or shutdown. It is the responsibility of the operators
of affected boilers and process heaters to start their limestone
injection in FBC boilers, dry scrubber, fabric filter, SNCR and SCR
systems appropriately to comply with relevant standards applicable
during normal operation. Startup ends and normal operating standards
apply when heat or steam is supplied for any purpose.
The EPA carefully considered fuels and potential operational
constraints of APCD when designing its work practices for periods of
startup and shutdown. The EPA notes that there is no technical barrier
to burning clean fuels (e.g., natural gas, distillate oil) for longer
portions of startup or shutdown periods at a boiler and the HAP
emission reduction benefits warrant additional utilization of such
fuels until the temperature and stack emissions pressure is sufficient
to engage the APCD. The EPA is aware that SNCR and SCR systems with
ammonia injection need to be operated within a prescribed and
relatively narrow temperature window to provide NOX
reductions. Further, the EPA is aware that dry scrubbers also need to
be operated close to flue gas saturation temperature, and that fabric
filters need to be operated at temperatures above the acid dew point.
Because these devices have specific temperature requirements for proper
operation, the EPA notes in its work practices that it is the
responsibility of the operators of affected boilers and process heaters
to start their SNCR, SCR, fabric filter and dry scrubber systems
appropriately to comply with relevant standards applicable during
normal operation.
I. Fuel Sampling Frequency
The sampling frequency for gaseous fuel-fired units that elected to
demonstrate that the unit meets the specification for mercury for the
unit designed to burn gas 1 subcategory has been revised in this final
rule. If the initial mercury constituents in the gaseous fuels are
measured to be equal to or less than half of the mercury specification,
no further sampling is required. If the initial mercury constituents
are greater than half but equal to or less than 75 percent of the
mercury specification, only semi-annual sampling need to be conducted.
If the initial mercury constituents are greater than 75 percent of the
mercury specification, monthly sampling is required.
J. Affirmative Defense
In the proposal, we used terms such as ``exceedance'' or ``excess
emissions'' in Sec. 63.7501, which created unnecessary confusion as to
when the affirmative defense could be used. In the final amended rule,
we have eliminated those terms and used the word ``violation'' to make
clear that the affirmative defense to civil penalties is available only
where an event that causes a violation of the emissions standard meets
the definition of malfunction under Sec. 63.2.
We have also eliminated the 2-day notification requirement that was
included in 40 CFR 63.7501(b) at proposal because we expect to receive
sufficient notification of malfunction events that result in violations
in other required compliance reports, such as the malfunction report
required under 40 CFR 63.7550(c). In addition, we have revised the 45-
day affirmative defense reporting requirement that was included in 40
CFR 63.7501(b) at proposal to require sources to include the report in
the first compliance, deviation or excess emission report due after the
initial occurrence of the violation, unless the compliance, deviation
or excess emission report is due less than 45 days after the violation.
In that case, the affirmative defense report may be included in the
second compliance, deviation or excess emission report due after the
initial occurrence of the violation. Because the affirmative defense
report is now included in a subsequent compliance, deviation or excess
emission report, there is no longer a need for the proposed 30-day
extension for submitting a stand-alone affirmative defense report.
Consequently, we are not including this provision in the final amended
rule. We have also re-evaluated the language concerning the use of off-
shift and overtime labor to the extent practicable and believe that the
language is not necessary. Thus, we have deleted that phrase from
section 63.7501(a)(2).
V. Other Actions We Are Taking
Section 307(d)(7)(B) of the CAA states that ``[o]nly an objection
to a rule or procedure which was raised with reasonable specificity
during the period for public comment (including any public hearing) may
be raised during judicial review. If the person raising an objection
can demonstrate to the Administrator that it was impracticable to raise
such objection within such time or if the grounds for such objection
arose after the period for public comment (but within the time
specified for judicial review) and if such objection is of central
relevance to the outcome of the rule, the Administrator shall convene a
proceeding for reconsideration of the rule and provide the same
procedural rights as would have been afforded had the information been
available at the time the rule was proposed. If the Administrator
refuses to convene such a proceeding, such person may seek review of
such refusal in the United States court of appeals for the appropriate
circuit (as provided in subsection (b)).''
As to the first procedural criterion for reconsideration, a
petitioner must show why the issue could not have been presented during
the comment period, either because it was impracticable to raise the
issue during that time or because the grounds for the issue arose after
the period for public comment (but within 60 days of publication of the
final action). The EPA is denying the petitions for reconsideration on
a number of issues because this criterion has not been met. In many
cases, the petitions reiterate comments made on the proposed June 2011
rule during the public comment period for that rule. On those issues,
the EPA responded to those comments in the final rule and made
appropriate revisions to the proposed rule after consideration of
public comments received. It is well-established that an agency may
refine its proposed approach without providing an additional
opportunity for public comment. See Community Nutrition Institute v.
Block, 749 F.2d at 58 and International Fabricare Institute v. EPA, 972
F.2d 384, 399 (D.C. Cir. 1992) (notice and comment is not intended to
result in ``interminable back-and-forth[,]'' nor is agency required to
provide additional opportunity to comment on its response to comments)
and Small Refiner Lead Phase-Down Task Force v. EPA, 705 F.2d 506, 547
(D.C. Cir. 1983) (``notice requirement
[[Page 7148]]
should not force an agency endlessly to repropose a rule because of
minor changes'')
In the EPA's view, an objection is of central relevance to the
outcome of the rule only if it provides substantial support for the
argument that the promulgated regulation should be revised. See Union
Oil v. EPA, 821 F.2d 768, 683 (D.C. Cir. 1987) (court declined to
remand rule because petitioners failed to show substantial likelihood
that final rule would have been changed based on information in
petition). See also the EPA's Denial of the Petitions to Reconsider the
Endangerment and Cause or Contribute Findings for Greenhouse Gases
under Section 202 of the Clean Air Act, 75 FR at 49556, 49561 (August
13, 2010). See also, 75 FR at 49556, 49560-49563 (August 13, 2010) and
76 FR at 4780, 4786-4788 (January 26, 2011) for additional discussion
of the standard for reconsideration under CAA section 307(d)(7)(B).
We are denying reconsideration on the following 57 issues contained
in the petitions for reconsideration because they failed to meet the
standard described above for reconsideration under CAA section
307(d)(7)(B). Specifically, on these issues, the petitioner has failed
to show the following: that it was impracticable to raise their
objections during the comment period or that the grounds for their
objections arose after the close of the comment period; and/or that
their concern is of central relevance to the outcome of the rule.
Therefore, the EPA is denying the petitions for reconsideration on the
issues for the reasons described below.
Issue: Delist gas units.
The petitioners (API, NPRA) requested that the EPA remove gas-fired
units from the section 112(c) list of source categories for which the
EPA is required to establish emissions standards under section 112(d).
The EPA is denying the petition for reconsideration for the following
reasons. First, the issue is outside the scope of this rulemaking,
which establishes emissions standards for new and existing units within
the major source boilers and process heaters source category. The EPA
did not solicit comment in the proposed rule regarding the scope of the
subcategory. Further, petitioners provide no information to support
delisting gas units under section 112(c)(9), which requires the EPA to
make certain findings before delisting any sources. In addition, the
petition does not address the D.C. Circuit's decision in NRDC v. EPA,
489 F.3d 1364 (2007), regarding the EPA's ability to delist
subcategories of a source category pursuant to section 112(c)(9). For
these reasons, the petitions do not provide support for the argument
that the regulation should be changed. For this reason, the petition
does not demonstrate that the issue is of central relevance to the
outcome of the final rule and the EPA is denying the request for
reconsideration.
Issue: Exempt natural gas hot water heaters with tanks greater than
120 gallons.
The petitioner (AIF) requested that the EPA exempt natural gas hot
water heaters with tanks greater than 120 gallons. While the EPA
disagrees with the petitioner regarding whether such units should be
subject to the emissions standards in this rule, the petitioner has not
demonstrated that it lacked the opportunity to comment on whether such
units should be required to meet emissions standards. The EPA proposed
work practice standards for such units in its June 2010 proposal, and
the petitioner had the opportunity to comment on whether such standards
should be applied to such units at all. Therefore, the EPA is denying
the request for reconsideration.
Issue: Exempt natural gas and distillate oil-fired circulating hot
water systems with a design capacity of 10 MMBtu/hr or less.
The petitioner (CIBO) requested that the EPA exempt natural gas and
distillate oil-fired circulation hot water systems that are not greater
than 10 MMBtu/hr. While the EPA disagrees with the petitioner regarding
whether such units should be subject to the emissions standards in this
rule, the petitioner has not demonstrated that it lacked the
opportunity to comment on whether such units should be required to meet
emissions standards. The EPA proposed emissions standards for such
units, and the petitioner had the opportunity to comment on whether
such standards should be applied to such units at all. In addition, the
petition does not provide any information to demonstrate that these
units should be delisted pursuant to section 112(c)(9). Therefore, the
EPA is denying the request for reconsideration.
Issue: Confirm in definitions that open flame heaters (e.g.,
asphalt tank heaters) are not process heaters.
The petitioners (API, NPRA) requested that the EPA clarify in the
definition of ``process heater'' that open flame heaters do not meet
the definition. While the EPA disagrees with the petitioners whether
clarification is needed in regards to open flame heaters, the
petitioners have not demonstrated that it lacked the opportunity to
comment on the proposed definition. The definition that the EPA
proposed clearly states that process heaters are enclosed devices in
which the combustion gases do not come into contact with process
materials, and as such, does not include open flame heaters. Therefore,
the EPA is denying reconsideration.
Issue: For blast furnace fuel-fired boiler exemption, compute the
90 percent BFG by volume threshold to exclude periods of BFG
curtailment.
The petitioners (AISI, ACCCI) requested that the EPA revise the
exemption for BFG fuel-fired boilers to exclude periods of BFG
curtailment. While the EPA disagrees with the petitioners regarding
revising the exemption, the petitioners have not demonstrated that it
lacked the opportunity to comment on the proposed exemption for BFG
fuel-fired boilers. The EPA proposed the exemption for these boilers,
and petitioners therefore had the opportunity to comment on whether the
exemption should apply to periods of BFG curtailment. Therefore, the
EPA is denying the request for reconsideration.
Issue: Exempt boilers whose flue gases are used in direct-fired
process heaters subject to other NESHAP.
The petitioner (CMI) requested that the EPA exempt from the rule
boilers whose flue gases are used in direct-fired process heaters that
are subject to other NESHAP. The final rule does not apply to such
units if they are subject to another NESHAP. The EPA does not see a
need for further clarification. Since the final rule does in fact
exempt these units, the EPA is denying the request for reconsideration.
Issue: Work practice standards do not meet EPA obligations under
112(c)(6).
The petitioner (Sierra Club) requested that the EPA establish
numeric emissions limits for Gas 1 units rather than work practice
standards. Specifically, the petitioner alleges that the work practice
standards do not meet the EPA's obligations under section 112(c)(6) of
the CAA, and that it was not the case that data were below the
detection level for all HAP emitted from these units. The EPA is
denying the request for reconsideration on this issue. While the EPA
disagrees with the petitioner's arguments regarding the legal authority
to establish work practice standards for Gas 1 units and the basis for
such standards, the petitioner has not demonstrated that it lacked the
opportunity to comment on this issue. The EPA proposed work practice
standards for Gas 1 units and explained in the proposal its rationale
for such standards, including the fact that a significant portion of
the
[[Page 7149]]
emissions data were below the detection level. 75 FR at 32024-25.
Therefore, the petitioner had the opportunity to comment on this issue,
and did in fact submit comments regarding the EPA's legal authority to
establish work practice standards for Gas 1 units. Therefore, the EPA
is denying reconsideration on this issue.
Issue: Work practices for small units are not justified by 112(h)
since small units were not given their own subcategory.
The petitioner (Sierra Club) requested that the EPA require small
units, those having a heat input capacity of less than 10 MMBtu/hr, to
meet numeric emissions limits rather than work practice standards. The
EPA is denying the request for reconsideration on this issue because
the petitioner has not demonstrated that it lacked the opportunity to
comment on this issue. The EPA proposed work practice standards for
these units and explained in the proposal its rationale for such
standards. 75 FR at 32024-25. The EPA did in fact receive comments
regarding the proposed standards, to which it responded in the final
rule. 76 FR at 15640. Moreover, the EPA notes that nothing in section
112(h) limits the EPA's discretion to establish work practice standards
to the establishment of such standards for an entire category or
subcategory. Therefore, the EPA is denying the request for
reconsideration.
Issue: PM is not an adequate surrogate for non-mercury metallic
HAP.
The petitioner (Sierra Club) requested that the EPA remove the PM
standard as a surrogate for non-mercury metallic HAP and instead adopt
a numeric limit for non-mercury metallic HAP because PM is not an
appropriate surrogate. The EPA is denying the request for
reconsideration on this issue. While the EPA disagrees with the
petitioner's argument regarding the suitability of PM as a surrogate
for non-mercury metallic HAP, the petitioner has not demonstrated that
it lacked the opportunity to comment on this issue. The EPA proposed PM
standards as a surrogate for non-mercury metallic HAP and explained in
the proposal the agency's basis for concluding that PM was an
appropriate surrogate. 75 FR at 32018. Therefore, the EPA is denying
the request for reconsideration.
Issue: Establish direct limits on organics or select a surrogate
besides CO.
The petitioner (Sierra Club) requested that the EPA remove the CO
standard as a surrogate for organic HAP and instead adopt a numeric
limit for these HAP, because CO is not an appropriate surrogate. The
EPA is denying the request for reconsideration on this issue. While the
EPA disagrees with the petitioner's argument regarding the suitability
of CO as a surrogate for organic HAP, the petitioner has not
demonstrated that it lacked the opportunity to comment on this issue.
The EPA proposed CO standards as a surrogate for organic HAP and
explained in the proposal the agency's basis for concluding that CO was
an appropriate surrogate. 75 FR at 32018. The EPA received comments on
this issue, including comments stating that CO is not an appropriate
surrogate for organic HAP. Therefore, the EPA is denying the request
for reconsideration.
Issue: Adopt an alternative THC emission standard.
The petitioner (CIBO) requested that the EPA adopt a THC emissions
standard as an alternative to the CO standard. The EPA is denying the
request for reconsideration on this issue. While the EPA disagrees with
the petitioner's argument regarding whether a THC alternative standard
is appropriate as a surrogate for non-dioxin organic HAP, the
petitioner has not demonstrated that it lacked the opportunity to
comment on this issue. The EPA raised in the proposal the possibility
of THC as a surrogate for non-dioxin organic HAP, and explained why the
use of CO as a surrogate was preferable. 75 FR at 32018. In addition,
the EPA did not receive any comments or data during the public comment
period on the proposed rule that would have enabled the agency to
establish a THC alternative standard, including THC emissions data, nor
did the petitioner provide any such data. Therefore, the petition does
not provide substantial support for its argument that the final rule
should be changed. For these reasons, the EPA is denying the petition
for reconsideration on this issue.
Issue: Regulation of Total dioxin/furans exceeds statutory
authority as only 2 compounds are in 112(b)(1).
The petitioners (AISI, ACCCI, AF&PA) alleged that the EPA lacks
statutory authority to regulate total dioxin/furans under CAA section
112, and that the EPA's response in the final rule explaining why it is
issuing a total dioxin/furan standard was not a logical outgrowth of
the proposed rule. The EPA is denying the request for reconsideration
on this issue. First, the EPA disagrees that the final rule is not a
logical outgrowth of the proposal. The EPA proposed emissions standards
for total dioxin/furans and adopted a final emissions standard for the
same pollutant. Therefore, the commenter had the opportunity to provide
its views during the public comment period regarding the EPA's proposed
emissions standard, including its views regarding the EPA's authority
to regulate the pollutant at issue. The fact that the EPA responded to
those comments does not mean that the petitioner lacked the opportunity
to comment--in fact, the petitioner did provide such comments. 76 FR at
15640. For this reason, the EPA is denying the petition for
reconsideration.
Issue: HCl is an inadequate surrogate for all acid gases.
The petitioner (Sierra Club) requested that the EPA remove the HCl
standard as a surrogate for acid gases and instead adopt a numeric
limit for these HAP, because HCl is not an appropriate surrogate. The
EPA is denying the request for reconsideration on this issue. While the
EPA disagrees with the petitioner's argument regarding the suitability
of HCl as a surrogate for acid gases, the petitioner has not
demonstrated that it lacked the opportunity to comment on this issue.
The EPA proposed HCl standards as a surrogate for acid gases and
explained in the proposal the agency's basis for concluding that HCl
was an appropriate surrogate. 75 FR at 32018. While the EPA had
emission data for HCl from hundreds of affected units upon which to
establish standards, the EPA did not have sufficient data on the other
acid gases to do so (hydrogen fluoride, hydrogen cyanide and chlorine).
The petitioner did not refer to any such data and, therefore, the issue
is not of central relevance to the outcome of the final rule.
Therefore, the EPA is denying the request for reconsideration.
Issue: Establish work practice for other organic HAP instead of
using CO as a surrogate.
The petitioners (AMP, JELD-WEN) requested that the EPA adopt a work
practice standard for organic HAP rather than a numeric emissions limit
based on CO as a surrogate for organic HAP. The EPA is denying the
request for reconsideration on this issue. While the EPA disagrees that
a work practice standard is appropriate for such HAP for the
subcategories for which the EPA adopted a numeric CO limit in the final
rule, the petitioners have not demonstrated that they lacked the
opportunity to comment on this issue. The EPA proposed numeric CO
limits rather than a work practice, and the petitioners had the
opportunity to provide their views during the public comment period on
the proposed rule regarding why it believed a work practice standard
should instead be
[[Page 7150]]
finalized. Therefore, the EPA is denying the petition for
reconsideration.
Issue: Allow health based compliance alternatives for HCl, other
acid gases and manganese.
The petitioners (AMP, AF&PA, AHFA, AISI, ACCCI, RPU, CIBO)
requested that the EPA adopt a HBES for HCl and other acid gases as
well as for manganese, pursuant to section 112(d)(4). The petitioners
also requested that the EPA grant reconsideration on this issue to
better address the comments and data submitted during the public
comment period for the proposed rule. The EPA is denying the request
for reconsideration of this issue. The EPA did not propose a HBES for
any pollutants, but did solicit public comment on such standards,
explaining its concerns regarding health-based standards, including the
lack of available data on which to base such standards. 75 FR at 32030.
The EPA received comments addressing those concerns and responded to
them in the final rule. 76 FR at 15642. Therefore, the petitioners have
not demonstrated that it lacked the opportunity to comment on this
issue. Further, the EPA received no data during the public comment
period for the proposed rule on which it could base a HBES for HCl,
other acid gases or manganese. Therefore, the petitions do not provide
substantial support to demonstrate that the final rule should be
changed. For these reasons, the EPA is denying the petition for
reconsideration.
Issue: Provide additional compliance alternatives according to
Executive Order 13563 (additional subcategories and HBES).
The petitioner (AHFA) requested that the EPA provide additional
compliance alternatives in the final rule pursuant to Executive Order
13563 (Improving Regulation and Regulatory Review), including HBES. The
EPA is denying the request for reconsideration on this issue because it
is not of central relevance. First, nothing in Executive Order 13563
affects the EPA's discretion to establish HBES under the CAA.
Additionally, the petition does not provide any information to address
our concerns regarding HBES or data to establish such standards.
Issue: Remove energy assessment requirements.
The petitioners (AHFA, AISI, ACCCI, API, NPRA, AIF, CIBO, AF&PA,
U.S. Sugar) requested that the EPA remove from the final rule the
requirement that existing sources conduct an energy assessment. The EPA
is denying the request for reconsideration on this issue. The EPA
proposed an energy assessment requirement as a beyond-the-floor
standard, and petitioners commented on that proposal. The EPA addressed
those comments in the final rule, and petitioners have not demonstrated
that they lacked the opportunity to comment on whether the EPA should
require an energy assessment, including the EPA's legal authority to do
so. 76 FR at 15631. Therefore, the EPA is denying the petition for
reconsideration. The EPA continues to believe that an energy assessment
is not only authorized by the CAA but required as a cost-effective
beyond-the-floor standard in accordance with section 112(d)(2).
Issue: Require energy assessment to be conducted every 5 years.
The petitioner (Washington Dept. of Ecology) requested that the EPA
require more frequent energy assessments. The EPA proposed a one-time
assessment (75 FR at p. 32036) and the petitioner has not demonstrated
it lacked the opportunity to comment on the frequency of the assessment
requirement. Therefore, the EPA is denying the petition.
Issue: Modify cost analysis to include potential fuel savings from
implementing assessment findings.
The petitioners (AIE, USCHPA) requested that the EPA modify its
cost impacts analysis to include potential fuel savings from
implementing energy assessment findings. The EPA is denying the
petition. The impacts analysis, including specific mention of how cost
savings for energy assessments were handled quantitatively, was
explained in the proposal (see 75 FR 32026), and the petitioner
therefore had the opportunity to comment on this issue. For this
reason, the EPA is denying the petition for reconsideration on this
issue.
Issue: Reconsider definition of ``cost effective.''
The petitioners (AIE, USCHPA) requested that the EPA reconsider the
definition of ``cost-effective'' in the final rule. The EPA is denying
the request for reconsideration on this issue. The EPA proposed to
define cost-effective energy conservation measures as any measure with
return of investment period of two years or less. 75 FR at 32036. The
petitioners have not demonstrated it lacked the opportunity to comment
on the proposed definition. Therefore, the EPA is denying the petition
for reconsideration.
Issue: Establish work practice for other organic HAP instead of
using CO surrogate.
The petitioners (AMP, JELD-WEN) requested that the EPA establish
work practice standards for controlling organic HAP instead of using CO
as a surrogate for organic HAP and establishing CO emission limits. The
EPA is denying the request for reconsideration on this issue. Use of CO
as a surrogate for organic HAP was subject to notice and comment. (75
FR 32018, 75 FR 32041). Responses to comment on this topic were
provided in RTC document, Volume 2, EPA-HQ-OAR-2002-0058-3289, see
section ``Choice of Regulated Pollutants: THC vs. CO vs. Other Organic
HAP''.
Issue: Provide alternative format for units of measure for CO
emission limits to allow sources to use their existing monitoring
equipment.
The petitioners (UARG, CIBO) requested that the EPA provide an
alternative format (ppm at X percent CO2) for units of
measure for CO emissions in addition to ppm at 3 percent oxygen. The
EPA is denying the petition because the petitioners do not demonstrate
that it was impracticable to comment on this issue. The format for
units of measure for the limits was provided in the proposed rule, and
petitioners could have commented on whether the proposed units were
appropriate.
Issue: New source emission limits are unachievable and the EPA
should collect additional fuel variability data from top performing
units to adjust the limits.
The petitioner (AF&PA) requested that the EPA adjust the emissions
limits for new sources by collecting additional data from the best
performing units that they believed would result in increased
variability. The petitioners have not demonstrated that they lacked the
opportunity to comment. We proposed standards based on the data we had,
including data collected during the ICR process in which petitioners
participated, and that data were available for public review.
Therefore, petitioners could have commented on this issue. Second, the
CAA requires that we base the standards on the sources for which we
have emissions information. Petitioners are always free to provide more
information to us and the EPA specifically requested new data at each
stage of the rulemaking to support the development of emission limits
for each subcategory. (75 FR 32041, 76 FR 28663, 76 FR 80612). The EPA
has incorporated revised data corrections or new data submittals in its
analysis for the final rule. The EPA is denying the request for
reconsideration.
Issue: Adjust the methodology for computing MACT floors to address
statistical errors and variability concerns.
The petitioners (AISI, ACCCI, AF&PA) requested that the EPA adjust
the
[[Page 7151]]
methodology for computing MACT floors to address statistical errors and
variability concerns, including: (1) Dataset reflects the ``best of the
best'' units; (2) misapplication of statistical formulae to address
distribution, confidence limits, and variability; and (3) failure to
address variability in emissions from one unit over time. The methods
used to compute the MACT floors were subject to notice and comment.
Where new data or data corrections have been submitted that might alter
data distributions, identifying best performers or application of fuel
variability factors, these changes have been made in the final rule,
but the general methodology remains the same. See Solite Corp. v. EPA,
952 F.2d 473, 485 (D.C. Cir. 1991) (public had sufficient notice of
final rule threshold calculations where methodology did not change
significantly from proposed rule). The EPA explained the MACT floor
methodology in the proposed rule, and addressed comments received on
the proposed methodology in the final rule (75 FR 32019-26, 32027-29,
76 15621-30, 76 FR 80614). Therefore, the EPA is denying the request
for reconsideration.
Issue: Modify the basis for ranking the top performing units.
The petitioner (WEPCO) requested that the EPA modify the basis for
ranking the top performing units, especially for new units, according
to the average performance of the unit. The EPA is denying the
petition. The methods used to rank units to establish the MACT floors
were subject to notice and comment. The EPA explained its methodology
in the proposed rule and addressed comments received on the ranking of
data for computing the MACT floor in the final rule (75 FR 32019-26,
32027-29, 76 FR 15627).
Issue: Do not use a pollutant-by-pollutant approach to establish
MACT floors.
The petitioners (AISI, ACCCI, AF&PA) requested that the EPA not use
a pollutant-by-pollutant approach to establish MACT floors. The
petitioners stated that this method is not a reasonable interpretation
of Section 112(d)(3) of the CAA and that MACT floors should reflect
levels achieved in practice, not aspirational controls. The EPA is
denying the petition for reconsideration on this issue because it does
not demonstrate that it was impracticable to comment on the issue. The
EPA proposed MACT floors based on the pollutant-by-pollutant
methodology, and therefore petitioners could, and in fact did, provide
comments opposing this approach. See 75 FR 32021, 32029. The EPA
addressed comments received on this approach in the final rule (76 FR
15621-23). Therefore, the EPA is denying the petition.
Issue: Revise approach to establish MACT floors where there is non-
detect data.
The petitioner (Sierra Club) requested that the EPA not use the
approach it used in the final rule based on the representative
detection level (RDL) to establish MACT floors because it does not
reflect actual emissions of any source within the subcategory. Further,
the petitioner questioned the basis of the selected detection level,
and whether or not other variability adjustments (e.g., UPL analysis)
sufficiently account for measurement imprecision. The EPA is denying
the petition. The three times representative detection level approach
was subject to notice and comment. The EPA explained its rationale for
this approach in the proposed rule (75 FR 32021) and responded to
comments received in the final rule (76 FR 15623, 76 FR 80611).
Issue: The approach used to set MACT floor limits for dioxin/furan
emissions is flawed and the EPA should establish an isomer-specific
approach.
The petitioner (WEPCO) requested that the EPA establish an isomer-
specific approach for dioxin/furan emissions because the three times
detection level approach for dioxin/furan emissions is flawed. The EPA
is denying the petition. This approach was subject to notice and
comment. Rationale and responses to comments on this approach were
provided at (75 FR 32021, 32041, 76 FR 15623). Further, the methods for
establishing a representative detection level for dioxin/furan have
been revised to account for the sensitivity of individual isomers, see
rationale provided at (76 FR 80606).
Issue: Incorporate a fuel variability factor for PM based on the
ash content of the fuel used by best performing units.
The petitioners (WEPCO, CIBO) requested that the EPA incorporate a
fuel variability factor for PM based on the ash content of the fuel
used by best performing units. The MACT floor methodology was explained
in the June 4, 2010 proposal which included fuel variability factors
that did not reflect the ash content of the fuel. Therefore, the
petitioner could have commented recommending that the EPA do so, and,
in fact, comments were provided on this issue. The EPA is denying the
petition for reconsideration on this issue because it does not
demonstrate that it was impracticable to comment on the issue.
Responses to comment on this topic were provided in RTC document,
Volume 1, EPA-HQ-OAR-2002-0058-3289, see section ``MACT Floor
Methodology: Fuel Analysis Variability''.
Issue: Allow energy assessors to determine the time needed to
conduct assessment.
The petitioner (Washington Dept. of Ecology) requested that the EPA
allow the energy assessor to determine the time needed to conduct the
energy assessment. The EPA is denying the petition. The duration of
energy assessments was subject to notice and comment and the duration
remains up to the affected source. Specific concerns with maximum
duration requirements included in the March 21, 2011 final rule were
clarified in the December 23, 2011 proposed notice of reconsideration.
(76 FR 80615)
Issue: The unit designed to burn gas 1 subcategory should allow for
limited use of liquid fuels.
The petitioners (ACC, CEG, API, NPRA) requested that the EPA allow
units in the Gas 1 subcategory for limited use of liquid fuels; for
example, units with a federally enforceable permit on back up fuels or
units burning 10 percent or less of its heat input from liquid fuels
should qualify as gas 1 units. The EPA is denying the petition because
it does not demonstrate that it was impracticable to comment on the
issue. The EPA proposed definitions of the various subcategories, and
petitioners had the opportunity to comment on those definitions,
including the proposed definition of the Gas 1 subcategory which did
allow for the limited use of liquid fuels. The EPA addressed comments
received on this issue in the final rule (76 FR 15620).
Issue: The unit designed to burn gas 1 subcategory should
automatically include other gaseous fuels such as petrochemical process
gas and landfill gas.
The petitioners (ACC, AIF, WM) requested that the EPA redefine the
unit designed to burn gas 1 subcategory to automatically include other
gaseous fuels such as petrochemical process gas and LFG, especially
when the LFG is routed to a treatment system prior to use or sale. The
EPA proposed definitions of units designed to burn gas 1 and units
designed to burn gas 2 (other), and therefore the petitioner had the
opportunity to comment on these definitions and to recommend that other
gases be included in the definition of the Gas 1 subcategory (75 FR
32017, 32065). The EPA addressed comments received on this issue in the
final rule (76 FR 15638). Therefore, the EPA is denying the petition.
[[Page 7152]]
Issue: Reconsider the emission standards established for the unit
designed to burn gas 2 subcategory.
Petitioners (AIF, CIBO, WM, CEG) requested that the EPA reconsider
the emission standards for the unit designed to burn gas 2 subcategory
in light of what they feel was a limited dataset and lack of data from
a diverse set of fuel types. The EPA is denying the petition. The MACT
floor methodology was open to notice and comment in the June 4, 2010
proposal. The EPA proposed emissions standards for this subcategory and
the petitioners had an opportunity to comment on the proposed standards
and the data on which the standards were based. The EPA further notes
that the CAA requires that the MACT standards be based on the best
performing sources for which the Administrator has emissions
information.
Issue: Adjust the ``metal process furnaces'' subcategory definition
to include any gas-fired process furnace.
The petitioners (AISI, ACCCI) requested that the EPA adjust the
``metal process furnaces'' subcategory definition to include any gas-
fired process furnace. The EPA is denying the petition. The definition
of the subcategory for metal process furnaces was subject to notice and
comment. (75 FR 32064, 76 FR 15620).
Issue: The designed to burn rationale for subcategorization is
arbitrary.
The petitioner (Sierra Club) alleged that the designed to burn
rationale for subcategorization is arbitrary, especially considering
the large number of co-fired units in the inventory. The EPA proposed
subcategories based on boiler design, and the petitioner has not
demonstrated that it was impracticable to comment on the issue. In
fact, the petitioner did submit comments on the proposed rule opposing
the EPA's proposed subcategorization approach. Therefore, the EPA is
denying the petition.
Issue: The EPA should consider exempting units from NSR.
The petitioners (MSU, PSU, Purdue, Citizens Thermal Energy)
requested that the EPA consider exempting units from NSR who switch
fuels, install pollution controls, or construct energy efficiency
projects to meet the requirements of this rule because complying with
the rule requirements will trigger NSR. The EPA is denying the
petition. The applicability of NSR is outside the scope of this
rulemaking. Moreover, it was not impracticable to comment on this issue
during the 2011 rulemaking, in fact, comments were submitted on this
issue, to which the EPA responded. See RTC document, Volume 2, EPA-HQ-
OAR-2002-0058-3289, DCN EPA-HQ-OAR-2002-0058-2729.1, excerpt 17.
Issue: Remove the 10 percent penalty for sources opting to use the
emission averaging compliance alternative.
The petitioners (AMP, MSU, PSU, Purdue, RPU, U.S. Sugar, Citizens
Thermal Energy) requested that the EPA remove the 10 percent penalty
for sources opting to use the emission averaging compliance
alternative. The EPA is denying the petition. The EPA proposed an
emissions averaging approach that included the 10 percent adjustment
factor. (75 FR 32035) Therefore, the petition does not demonstrate that
it was impracticable to comment on this issue. Responses to comment on
this topic were provided in RTC document, Volume 2, EPA-HQ-OAR-2002-
0058-3289, see section ``Emissions Averaging.''
Issue: Allow emissions averaging across subcategories.
The petitioners (MSU, PSU, Purdue, RPU, Citizens Thermal Energy)
requested that the EPA allow emissions averaging across subcategories.
The EPA is denying the petition. The EPA proposed an emissions
averaging approach that did not allow averaging across subcategories,
and petitioners therefore had the opportunity to comment recommending
that the EPA allow such averaging. Responses to comment on this topic
were provided in RTC document, Volume 2, EPA-HQ-OAR-2002-0058-3289, DCN
EPA-HQ-OAR-2002-0058-3213.1, excerpt 175.
Issue: Allow a source's actual heat input instead of the maximum
design heat input to be used in the emissions averaging provisions.
The petitioner (CIBO) requested that the EPA allow a source's
actual heat input instead of the maximum design heat input to be used
in the emissions averaging provisions of the final rule. The EPA
proposed an emissions averaging approach that was based on the maximum
rated heat input capacity, and petitioners therefore had the
opportunity to comment recommending that the EPA base the averaging on
actual heat input. Therefore, the EPA is denying the petition.
Issue: Reduce stack testing frequency to once every five years to
reduce burden on facilities.
The petitioners (ACC, CIBO, JELD-WEN) requested that the EPA reduce
stack testing frequency to once every 5 years and rely on the extensive
set of continuous parameter monitoring in order to reduce burden on
facilities. The EPA is denying the petition. The EPA proposed to
require stack testing every year. The petition does not demonstrate
that it was impracticable to comment on this issue, and the petitioners
could have submitted comments requesting less frequent stack testing.
Issue: Incorporate detailed fuel sampling procedures using
incorporation by reference mechanisms instead of detailing sampling
procedures in the regulatory language.
The petitioner (CIBO) requested that the EPA incorporate detailed
fuel sampling procedures using incorporation by reference mechanisms
and citing credible literature (e.g., American Society for Testing and
Materials) instead of detailing sampling procedures in the regulatory
language since sampling procedures are subject to change over time. The
EPA is denying the petition because the petitioner has not demonstrated
that it was impracticable to comment on this issue. The EPA proposed
fuel sampling procedures in the regulatory text in the June 4, 2010
proposal, and the petitioner therefore had the opportunity to comment
recommending its preferred approach.
Issue: Remove the advanced submittal requirement for site-specific
fuel monitoring plans before each analysis.
The petitioner (UARG) requested that the EPA remove the advanced
submittal requirement for site-specific fuel monitoring plans before
each analysis, especially if monthly frequency is maintained. If the
fuel monitoring plan requirement remains, the petitioner requests that
the EPA remove the requirement to report things that might change, such
as unanticipated fuel use (based on unanticipated fuel changes). The
EPA is denying the petition and disagrees with the commenter. First,
the EPA proposed a fuel monitoring plan, and petitioners had the
opportunity to comment on the plan requirement. The final rule requires
submittal of a fuel monitoring plan 60 days before demonstrating
initial compliance. The rule does not require re-submittal of this plan
before each monthly analysis, see 40 CFR section 63.7521(b)(1).
Issue: Allow EPA Method 5B to demonstrate compliance with PM
emission limits.
The petitioner (UARG) requested that the EPA allow EPA Method 5B to
demonstrate compliance with PM emission limits. The EPA is denying the
petition because it does not demonstrate that it was impracticable to
comment on this issue. The EPA proposed methods to demonstrate
compliance in the June 4, 2010 proposal and did not propose to allow
Method 5B for PM compliance demonstrations. Therefore, the petitioner
had the opportunity to submit comments recommending that the EPA allow
the use of this method. For this
[[Page 7153]]
reason, the EPA is denying the petition on this issue.
Issue: Remove or make references to Methods 2, 2F, 2G and 4
optional.
The petitioner (UARG) requested that the EPA remove or make
references to EPA Methods 2, 2F, 2G and 4 optional. The EPA is denying
the petition because it does not demonstrate that it was impracticable
to comment on this issue. The EPA proposed methods to demonstrate
compliance in the June 4, 2010 proposal and did not propose to make EPA
Methods 2, 2F, 2G and 4 optional. Therefore, the petitioner had the
opportunity to submit comments recommending that the EPA make the use
of these methods optional. For this reason, the EPA is denying the
petition on this issue.
Issue: Allow sources to petition for alternative PM monitoring
requirements based on source-specific limitations.
The petitioner (CEG) requested that the EPA allow sources to
petition for alternative PM monitoring requirements based on source-
specific limitations (e.g., common stacks with more than one
subcategory). The EPA is denying this petition because it is not of
central relevance to this rulemaking. The General Provisions at 40 CFR
63.8 allow sources to petition the EPA for alternative monitoring
plans. Therefore, no such provision is needed in this final rule.
Issue: Allow sources with overlapping CEMS regulations to comply
with existing QA/QC plans or 40 CFR part 75 Appendices A and B.
The petitioners (CIBO, CMI) requested that the EPA allow sources
with overlapping CEMS regulations to comply with existing QA/QC plans
or 40 CFR part 75 Appendices A and B. The EPA is denying this petition
because it is not of central relevance to this rulemaking.
Issue: No justification or discussion was provided on why the EPA
selected 12 hours as the averaging time period and also why the EPA
selected block averages instead of rolling averages.
The petitioner (Sierra Club) alleges that the EPA provided no
justification or discussion explaining why the EPA selected 12 hours as
the averaging time period and why the EPA selected block averages
instead of rolling averages for parameter monitor. The petitioner
requested that the EPA clarify that the averaging times for continuous
parameter monitoring should be the same as the averaging times during
the most recent performance test. Averaging times were open to notice
and comment in the June 4, 2010 proposal. In the June 2010 proposal, we
required that parameters be set based on 4-hour block averages during
the compliance test, and that continuous compliance be demonstrated by
monitoring 12-hour block average values for most parameters. We
selected this averaging period to reflect operating conditions during
the performance test to ensure the control system is continuously
operating at the same or better level as during a performance test
demonstrating compliance with the emission limits. Therefore, the EPA
is denying the petition.
Issue: The EPA position regarding treatment of ``out-of-control''
and ``maintenance'' periods as deviations is not supported or
explained.
The petitioner (UARG) alleges that the EPA position regarding
treatment of ``out-of-control'' and ``maintenance'' periods as
deviations is not supported or explained. The petitioner requested that
the EPA revise the definition of ``deviation'' to be consistent with
how deviation is treated with respect to CO CEMS and CPMS. The EPA is
denying the petition. The definition of deviations was open to notice
and comment in the June 4, 2010 proposal.
Issue: Require checks of pressure monitoring taps only if reading
is abnormal.
The petitioner (CMI) requested that the EPA require checks of
pressure monitoring taps only if reading is abnormal. The requirement
to check pressure tap pluggage daily was open to notice and comment in
the June 2010 proposal. In addition, the EPA is denying this petition
because it is not of central relevance to this rulemaking.
Issue: The EPA has not sufficiently correlated emission limits to
operating parameters and should not set enforceable limits on maximum
and minimum control device operating parameters.
The petitioners (UARG, AMP, CIBO) alleges that the EPA has not
sufficiently correlated emission limits to operating parameters and
requested the EPA not to set enforceable limits on maximum and minimum
control device operating parameters. One petitioner (CIBO) requested
that the rule should allow sources to set their own ESP secondary
voltage requirement based on load and coal quality since power
consumption by an ESP is influenced by factors other than operating
load, including ESP design, amount of PM collected, and resistivity of
the PM. Other petitioners (UARG and AMP) also indicate that the limits
set on control devices inhibit the flexibility to operate control
devices with a margin of safety. The EPA is denying the petition.
Operating limits were open to notice and comment in the June 4, 2010
proposal.
Issue: The EPA should delay incorporating PS 17 in this rule until
the revisions for PS 17 are completed.
The petitioner (UARG) requested that the EPA delay incorporating PS
17 in this rule, which outlines how to select and install CPMS, until
the revisions for PS 17 are completed.
The EPA is denying this petition. The final rule did not
incorporate PS 17, or any other PS, in the provision regarding
selection and installation of CPMS and ongoing quality assurance of
data from CPMS. Comments related to revising PS 17 are outside the
scope of this rulemaking. (RTC document, Chapter 11, EPA-HQ-OAR-2002-
0058-3289, DCN EPA-HQ-OAR-2002-0058-2960.1, excerpt 150).
Issue: The EPA should not set an enforceable operating limit on
opacity.
The petitioner (UARG) alleged that there is insufficient
correlation between opacity and PM emissions and requested that the EPA
not set an enforceable operating limit on opacity. The EPA is denying
the petition. The EPA proposed opacity limits in the June 4, 2010
proposal and the petitioner therefore had the opportunity to comment on
the proposed limits, including comments requesting that no limit be
established.
Issue: Update outdated BLDS Guidance.
The petitioner (UARG) requested that the EPA update the outdated
BLDS Guidance that is currently incorporated by reference. The EPA is
denying this petition. The current guidance document is the most recent
guidance available and comments related to revising the guidance
document are outside the scope of this rulemaking. (RTC document,
Chapter 11, EPA-HQ-OAR-2002-0058-3289, DCN EPA-HQ-OAR-2002-0058-2997.1,
excerpt 10).
Issue: The EPA should reconsider emission limits for HCl on coal-
fired boilers using a hot-side ESP for particulate control.
The petitioners (MSU, PSU, Purdue, Citizens Thermal Energy)
requested that the EPA reconsider emission limits for HCl on coal-fired
boilers using a hot-side ESP for particulate control. The petitioners
are unaware of any HCl control devices that are compatible with a hot-
side ESP. The EPA is denying the petition. The basis for
subcategorization was subject to notice and comment. The EPA did not
propose a separate subcategory for such units, and the petitioner could
have commented recommending that the agency do so. (75 FR 32012, 76 FR
15617-18, 76 FR 80607) Further, the EPA disagrees with the petitioner
that the subcategories
[[Page 7154]]
could be based on the level of controls installed on the unit.
Issue: The EPA should change electronic reporting requirements to
avoid WebFIRE and ERT shortcomings.
The petitioner (UARG) requested that the EPA change the electronic
reporting requirements to avoid WebFIRE and ERT shortcomings. The
petitioner requested that to meet the EPA's obligations under the
Paperwork Reduction Act the EPA specify each individual data item
requested in the ERT. The petitioner also requests that the EPA explain
how the ERT electronic signature mechanisms will meet the requirements
of the Cross-Media Electronic Reporting Rule.
The EPA is denying the petition because it does not demonstrate
that it was impracticable to comment on this issue. The EPA proposed to
require the use of the ERT and WebFIRE, and the petitioner therefore
had the opportunity to comment on any concerns with the proposed
approach.
Issue: Eliminate gas curtailment notification requirements or
adjust the frequency of these notifications to be consistent with the
reporting requirements in the Title V program.
The petitioner (AIF) requested that the EPA eliminate the gas
curtailment notification requirements or adjust the frequency of these
notifications to be consistent with the semi-annual reporting
requirements in the Title V program. The EPA is denying the petition.
Reporting requirements were open to notice and comment in the June 4,
2010 proposal.
Issue: Allow facilities to become area or synthetic minor sources
instead of installing controls.
The petitioner (GPSP) requested that the EPA allow facilities to
become area or synthetic minor sources instead of installing controls.
The EPA is denying the petition. Whether or not sources elect to become
area or synthetic minor sources is not of central relevance to this
rulemaking, as nothing in this rule affects whether or how a source can
become a synthetic minor source (RTC document, EPA-HQ-OAR-2002-0058-
3289, Volume 1, DCN EPA-HQ-OAR-2002-0058-3176.2, excerpt 4).
VI. Impacts of This Final Rule
A. What are the incremental air impacts?
Table 4 of this preamble illustrates, for each basic fuel
subcategory, the total emissions reductions achieved by the final
amended rule (i.e., the difference in emissions between a boiler or
process heater controlled to the amended floor level of control and
boilers or process heaters at the current baseline) for new and
existing sources. Nationwide emissions of selected HAP (i.e., HCl, HF,
mercury, metals, and VOC) will be reduced by 44,300 tpy. This is an
incremental increase of 4,000 tpy in HAP reductions compared to the
estimates in the March 2011 final rule. This increase is due mainly to
changes in the inventory (336 units were added since the March 2011
inventory). Excluding the changes in the inventory, the amendments to
the regulatory provisions themselves resulted in a decrease of 1,100
tpy of estimated reductions, part of this incremental reduction in HAP
is contributed to edits to the baseline emission data received since
the March 2011 final rule, as well as changes to the subcategories and
emission limits as a result of this amended rule. The amendments to the
final rule are expected to result in an additional 4,600 tpy of
reductions in HCl emissions. The amendments are also expected to have a
modest effect on mercury, estimated to range from a slight decrease of
0.12 tpy up to a slight increase of 0.96 tpy in emission reductions as
a result of the changes to the regulatory requirements. Reductions in
emissions of filterable PM will decrease by 18,500 tpy due to the final
amended rule. Reductions in emissions of non-mercury metals (i.e.,
antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead,
manganese, nickel, and selenium) will decrease by 260 tpy. In addition,
the amendments are estimated to result in an additional 50,100 tpy of
reductions in SO2 emissions. A discussion of the methodology
used to estimate emissions, emissions reductions, and incremental
emission reductions is presented in ``Revised (August 2012) Methodology
for Estimating Cost and Emission Impacts for Industrial, Commercial,
and Institutional Boilers and Process Heaters NESHAP--Major Source'' in
the docket.
Table 4--Summary of Total Emissions Reductions for the Final Amended Rule
[tons/yr]
----------------------------------------------------------------------------------------------------------------
Non
mercury
Source Subcategory HCl PM metals Mercury \b\ VOC
\a\
----------------------------------------------------------------------------------------------------------------
Existing Units................ Limited Use...... 1 2 0.42 2.1E-04.......... 0.48
Solid units...... 36,737 21,367 147 0.4 to 1.5...... 1,619
Liquid units..... 2,143 9,434 2,315 0.9 to 1......... 620
Non-Continental 35 3 1 0.01 to 0.02..... 23
Liquid units.
Gas 1 (NG/RG) 20 117 0.3 0.01............. 88
units.
Gas 1 0.4 3 0.02 0.001............ 27
Metallurgical
Furnaces.
Gas 2 (other) 4 8 0.06 3.8E-03 to 4.6E- 40
units. 03.
New Units..................... Solid units...... 0 351 5 0.02............. 0
Liquid units..... 0 0 0 0................ 0
Gas 1 units...... 0 0 0 0................ 0
Gas 1 0 0 0 0................ 0
Metallurgical
Furnaces.
Gas 2 (other) 0 0 0 0................ 0
units.
----------------------------------------------------------------------------------------------------------------
\a\ Includes antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium.
\b\ Mercury reductions are presented as a range due to adjustments on reported fractions and limits of
detection. See memorandum entitled ``Revised (March 2012) Methodology for Estimating Cost and Emissions
Impacts for Industrial, Commercial, Institutional Boilers and Process Heaters National Emission Standards for
Hazardous Air Pollutants--Major Source'' for a description of the two methods for estimating mercury
reductions.
[[Page 7155]]
B. What are the incremental water and solid waste impacts?
The EPA estimated the additional water usage that would result from
installing wet scrubbers to meet the amended emission limits for HCl
would be 556 million gallons per year for existing sources compared to
the current baseline. In addition to the increased water usage, an
additional 160 million gallons per year of wastewater would be produced
for existing sources. Only half of these incremental changes are due to
changes in the regulatory provisions. The other half is due to changes
in the number of identified existing units and projected new units. The
annual costs of treating the additional wastewater are $1.2 million.
These additional costs are accounted for in the incremental control
cost estimates.
The EPA estimated the additional solid waste that would result due
to the amendments to be 138,000 tpy, with nearly all due to changes in
the regulatory provisions. Solid waste is generated from flyash and
dust captured in PM and mercury controls as well as from spent carbon
that is injected into exhaust streams or used to filter gas streams.
The costs of handling the additional solid waste generated are $5.8
million. These costs are also accounted for in the incremental control
costs estimates.
A discussion of the methodology used to estimate incremental
impacts is presented in ``Revised (August 2012) Methodology for
Estimating Cost and Emission Impacts for Industrial, Commercial, and
Institutional Boilers and Process Heaters NESHAP--Major Source'' in the
docket.
C. What are the incremental energy impacts?
The EPA estimated that the March 2011 final rule would result in an
increase of about 1.4 billion kWh/yr in national energy usage from the
electricity required to operate control devices, such as wet scrubbers,
electrostatic precipitators and fabric filters which are expected to be
installed to meet the final rule. The amendments are expected to
decrease energy usage by a net 143 million kWh/yr compared to the March
2011 rule. These reductions are driven by the regulatory provisions of
these amendments. Additionally, the EPA expects these amendments will
result in a decrease of 4.4 million MMBtu/yr in fuel savings, compared
with the estimates in the March 2011 final rule.
D. What are the incremental cost impacts?
For these final amendments, we estimated the incremental difference
between the national costs impacts for the final amended rule and the
March 2011 final rule. First, we determined the control measures, work
practices, and monitoring and testing requirements that would be
required by boilers and process heaters located at major source
facilities to comply with the final amended rule. To estimate the
national cost impacts of the final amended rule for existing sources,
we used the identical methodology used to estimate the cost impacts for
the March 2011 final rule with one exception. In this revised analysis,
it was assumed that several liquid fuel units that reported natural gas
firing capability would switch to natural gas as a compliance option
instead of installing add-on controls to demonstrate compliance with
the emission limits. Thus, the only costs to these units would be the
tune-up work practice costs. A discussion of the methodology used to
estimate cost impacts is presented in ``Revised (August 2012)
Methodology for Estimating Cost and Emission Impacts for Industrial,
Commercial, and Institutional Boilers and Process Heaters NESHAP--Major
Source'' in the docket.
The resulting total national cost impact of the final amended rule
is $4.7 billion in capital expenditures and $1.5 billion per year in
total annual costs, considering fuel savings. The total capital
expenditures are slightly lower than estimated for the March 2011 final
rule, but the total annual costs are slightly higher than estimated for
the March 2011 final rule. See 76 FR 15651. The total capital and
annual costs include costs for control devices, work practices, testing
and monitoring.
In order to determine the incremental cost impacts of the amended
requirements and emission limits, we first estimated the cost impacts
of the additional existing boilers and process heaters added to the
Boiler MACT inventory database since promulgation of the March 2011
final rule and the revised number of new boilers and process heaters
that could be potentially constructed. Since the March 2011 final rule,
we became aware of 72 major source facilities that were not previously
in the Boiler MACT inventory database. Adding the boilers and process
heaters located at these newly identified major source facilities
resulted in 73 additional coal-fired units, 32 additional biomass-fired
units, 82 additional oil-fired units, and 149 additional gas-fired
units. Our revised number of new boilers and process heaters included
82 additional biomass units, 1,728 additional gas 1 units and 13 fewer
liquid units.
The resulting cost impact for these additional existing and new
boilers and process heaters is $1.0 billion in capital expenditures and
$0.31 billion per year in total annual costs, considering fuel savings.
Therefore, discounting the added costs for the additional boilers
and process heaters included in the costs analysis, the estimated
incremental cost impacts for these amended requirements on existing and
new boilers and process heaters are $1.0 billion in capital
expenditures and $0.13 billion per year in total annual costs less than
the costs estimated in the March 2011 rule.
Table 5 of this preamble shows the total capital and annual cost
impacts of the final amended rule for each subcategory. Costs include
testing and monitoring costs, but not recordkeeping and reporting
costs.
Table 5--Summary of Total Capital and Annual Costs for New and Existing Sources for the Final Amended Rule
--------------------------------------------------------------------------------------------------------------------------------------------------------
Testing and
monitoring Annualized cost
Source Subcategory Estimated/projected number of Capital costs annualized (10\6\ $/yr)
affected units (10\6\ $) costs (10\6\ $/ (considering
yr) fuel savings)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Existing Units........................... Coal units.................. 621.......................... 2,554 46 904
Biomass units............... 502.......................... 405 29 109
Heavy Liquid units.......... 319.......................... 761 5.4 221
Light Liquid units.......... 615.......................... 712 4.2 166
Non-Continental Liquid units 21........................... 62 0.8 17
Gas 1 (NG/RG) units......... 11,929....................... 77 0.9 (295)
[[Page 7156]]
Gas 2 (other) units......... 129.......................... 138 2.3 58
Energy Assessment........................ ALL......................... 1,700 (Facilities)........... N/A N/A 28
New Units................................ Coal units.................. 0............................ 0 0 0
Biomass units............... 82........................... 381 5.6 \a\ 99
Liquid units................ 0............................ 0 0 0
Gas 1 (NG/RG) units......... 1,762........................ 11 0 \a\ 5.1
Gas 2 (other) units......... 0............................ 0 0 0
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Total annualized costs for new units do not account for fuel savings since no fuel savings are estimated in the first year for new units.
Potential control device cost savings and increased recordkeeping
and reporting costs associated with the emissions averaging provisions
in the final rule are not accounted for in either the capital or
annualized cost estimates.
A discussion of the methodology used to estimate cost impacts is
presented in ``Revised (August 2012) Methodology for Estimating Cost
and Emission Impacts for Industrial, Commercial, and Institutional
Boilers and Process Heaters NESHAP--Major Source'' in the docket.
E. What are the economic impacts?
The EPA analyzed the economic impacts of this final amended rule
using the methodology that was discussed in the March 2011 final rule
RIA and in the preamble to the March 2011 final rule. See FR 76 15651.
The market impact results are very similar to the results presented in
the March 2011 final rule and the RIA. The agency's economic model
suggests the average national price increases for industrial sectors
are less than 0.01 percent, while average annual domestic production
may fall by less than 0.01 percent.
Because of higher domestic prices, imports slightly rise. The
results for sales tests for small businesses were somewhat reduced than
those calculated for the March 2011 final rule. For the sales tests
using small companies identified in the Combustion Survey, the mean
cost to receipts dropped from 4 percent in the RIA to 3 percent for
this final amended rule and the median was 0.2 percent for the RIA and
also 0.2 percent for this final amended rule. The number of parent
companies with sales tests exceeding 3 percent dropped from 8 in the
RIA to 5 for this final amended rule. There was no change in the
results for small public entities. Median cost is still about $1.1
million and representative small major public entities would have cost-
to-revenue ratios above 10 percent. The change in employment estimates
between the RIA and the final amended rule is minimal. In the RIA for
the March 2011 final rule, we estimated employment changes ranging
between -3,100 to +6,500 employees, with a central estimate of +1,700.
For this final amended rule we estimate employment changes ranging
between -2,600 to +5,400 employees, with a central estimate of +1,400.
These estimated annual employment changes compared to the baseline
employment, and are for the time period for which the annualized cost
applies (2015 to 2029).
F. What are the benefits of this final rule?
We calculated health benefits using the methodology described in
the RIA prepared for the March 21, 2011 final rule. We incorporated the
revised emission reductions estimated for this reconsideration final
rule into the analysis. We were unable to estimate the benefits from
reducing exposure to HAP and ozone, ecosystem impairment and visibility
impairment, including reducing 180,000 tons of carbon monoxide, 39,000
tons of HCl, 500 tons of HF, 2,500 tons of other metals and 3,100 to
5,300 pounds of mercury. Please refer to the full description of the
unquantified benefits as well as technical details of the analysis and
its limitations and uncertainties in the final Boiler RIA (March 2011).
These monetized benefits are approximately 23 percent higher than the
March 2011 final rule benefits due to the increase in SO2
emission reductions associated with the additional units affected by
the rule and the revised HCl limit. We estimate the total monetized
benefits of this final regulatory action to be $27 billion to $67
billion at a 3 percent discount rate and $25 to $61 billion at a 7
percent discount rate. All estimates are for the implementation year
(2015) in 2008$. A summary of the monetized benefits estimates at
discount rates of 3 percent and 7 percent is provided in Table 6 of
this preamble. A summary of the avoided health incidences is provided
in Table 7 of this preamble.
Table 6--Summary of the Monetized Benefits Estimates for the Final Boiler MACT
[millions of 2008$] a b
----------------------------------------------------------------------------------------------------------------
Emissions
Pollutant reductions Total monetized benefits Total monetized benefits
(tons) (at 3% discount rate) (at 7% discount rate)
----------------------------------------------------------------------------------------------------------------
PM2.5-related benefits
----------------------------------------------------------------------------------------------------------------
Direct PM2.5............................ 14,139 $1,200 to $2,900............ $1,100 to $ $2,700
SO2..................................... 572,000 $26,000 to $64,000.......... $24,000 to $61,000
-----------------------------------------
[[Page 7157]]
Total............................... ........... $27,000 to $67,000.......... $25,000 to $61,000.
----------------------------------------------------------------------------------------------------------------
\a\ All estimates are for the implementation year (2015), and are rounded to two significant figures so numbers
may not sum across rows. All fine particles are assumed to have equivalent health effects because the
scientific evidence is not yet sufficient to allow differentiation of effect estimates by particle type.
Benefits from reducing hazardous air pollutants (HAP) are not included. These estimates do not include energy
disbenefits valued at $24 million (using a 3 percent discount rate). These benefits reflect existing boilers
and new boilers anticipated to come online by 2015.
\b\ There are some slight differences in the emission reductions used in the RIA and those used in the air
impacts section of this preamble due to some late changes in the data that were received after the RIA was
completed. Refer to the memoranda ``Revised (August 2012) Methodology for Estimating Cost and Emission Impacts
for Industrial, Commercial, and Institutional Boilers and Process Heaters NESHAP--Major Source'' for a
discussion of the differences.
Table 7--Summary of the Avoided Health Incidences for the Final Boiler
MACT a
------------------------------------------------------------------------
Avoided health
incidences
------------------------------------------------------------------------
Premature Mortality..................................... 3,000-7,900
Morbidity............................................... ..............
Chronic Bronchitis...................................... 2,000
Acute Myocardial Infarction............................. 5,000
Hospital Admissions, Respiratory........................ 750
Hospital Admissions, Cardiovascular..................... 1,600
Emergency Room Visits, Respiratory...................... 3,000
Acute Bronchitis........................................ 4,600
Work Loss Days.......................................... 390,000
Asthma Exacerbation..................................... 51,000
Minor Restricted Activity Days.......................... 2,300,000
Lower Respiratory Symptoms.............................. 55,000
Upper Respiratory Symptoms.............................. 41,000
------------------------------------------------------------------------
\a\ All estimates are for the implementation year (2015), and are
rounded to two significant figures. All fine particles are assumed to
have equivalent health effects because the scientific evidence is not
yet sufficient to allow differentiation of effect estimates by
particle type. Benefits from reducing HAP are not included. These
benefits reflect existing boilers and new boilers anticipated to come
online by 2015.
G. What are the incremental secondary air impacts?
For units adding controls to meet the amended emission limits, we
anticipate very minor secondary air impacts. The combustion of fuel
needed to generate additional electricity would yield slight increases
in emissions, including NOX, CO, PM and SO2 and
an increase in CO2 emissions. Since NOX and
SO2 are covered by capped emissions trading programs and
methodological limitations prevent us from quantifying the change in CO
and PM, we do not estimate an increase in secondary air impacts for
this final rule from additional electricity demand. We do estimate
greenhouse gas impacts, which result from increased electricity
consumption, to be 859,200 tpy from existing units and 79,700 tpy from
new units. This is 19,200 tpy less than the estimated greenhouse gas
impacts associated with the March 2011 final rule.
VII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
Under section 3(f)(1) of Executive Order 12866 (58 FR 51735,
October 4, 1993), this action is an ``economically significant
regulatory action'' because it is likely to have an annual effect on
the economy of $100 million or more or adversely affect in a material
way the economy, a sector of the economy, productivity, competition,
jobs, the environment, public health or safety, or state, local, or
tribal governments or communities. Accordingly, the EPA submitted this
action to the OMB for review under Executive Orders 12866 and 13563 (76
FR 3821, January 21, 2011) and any changes made in response to the OMB
recommendations have been documented in the docket for this action.
The EPA did prepare a new RIA for this action. The EPA prepared an
assessment of the changes in the costs and benefits of this final rule
compared to the costs and benefits associated with the March 21, 2011,
final rule. Overall, the costs and impacts are estimated to be similar
to the costs and impacts associated with the previous final rule,
although the distribution is somewhat different and the number of
affected units in the inventory has increased by about 302 units. When
comparing the costs using only those sources that were part of the
final rule inventory, the costs have decreased. The EPA re-ran the
multimarket model to assess changes in economic impacts, and this
analysis confirmed that the overall economic impacts are similar to the
previous final rule. The benefits are projected to increase by about 20
percent because of the increase in the estimated SO2
reductions. A summary of the costs and benefits of the previous final
rule is provided in the preamble to the previous final rule (see 76 FR
15658) and the detailed analysis for the previous final rule is
provided in the RIA for the previous final rule. In addition, memoranda
are provided in the docket to document the changes in costs, economic
impacts, and benefits associated with this final rule, shown in Table
8.
Table 8--Summary of the Monetized Benefits, Social Costs and Net
Benefits for the Final Boiler MACT Reconsideration in 2015
[Millions of 2008$] \1\
------------------------------------------------------------------------
3 percent discount 7 percent discount
rate rate
------------------------------------------------------------------------
Total Monetized Benefits \2\... $27,000 to $67,000. $24,000 to
$61,000.
Total Social Costs \3\......... $1,400 to $1,600... $1,400 to $1,600.
Net Benefits................... $26,000 to $65,000. $23,200 to
$59,000.
------------------------------------------------------------------------
[[Page 7158]]
Non-monetized Benefits......... Health effects from exposure to HAP
(39,000 tons of HCl, 500 tons of HF,
3,100 to 5,300 pounds of mercury, and
2,500 tons of other metals).
Health effects from exposure to other
criteria pollutants (180,000 tons of
CO and 572,000 tons of SO2).
Ecosystem effects.
Visibility impairment.
------------------------------------------------------------------------
\1\ All estimates are for the implementation year (2015), and are
rounded to two significant figures.
\2\ The total monetized co-benefits reflect the human health benefits
associated with reducing exposure to PM2.5 through reductions of PM2.5
precursors such as directly emitted particles, SO2, and NOX and
reducing exposure to ozone through reductions of VOC. It is important
to note that the monetized benefits include many but not all health
effects associated with PM2.5 exposure. Monetized benefits are shown
as a range from Pope et al. (2002) to Laden et al. (2006). These
models assume that all fine particles, regardless of their chemical
composition, are equally potent in causing premature mortality because
the scientific evidence is not yet sufficient to support the
development of differential effects estimates by particle type. These
estimates include the energy disbenefits valued at $24 million (using
the 3 percent discount rate), which do not change the rounded totals.
CO2-related disbenefits were calculated using the ``social cost of
carbon'', which is discussed further in the RIA.
\3\ The methodology used to estimate social costs for one year in the
multimarket model using surplus changes results in the same social
costs for both discount rates.
B. Paperwork Reduction Act
The OMB has approved the information collection requirements
contained in the March 21, 2011 final rule under the provisions of the
Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB
control number 2060-0551. The EPA has updated the supporting statement
to reflect the final inventory and burden estimates associated with
this action since some of the monitoring, recordkeeping and reporting
requirements have changed since the March 21, 2011 final rule. These
revised estimates have been sent to OMB for review and approval.
The information requirements are based on notification,
recordkeeping, and reporting requirements in the NESHAP General
Provisions (40 CFR part 63, subpart A), which are mandatory for all
operators subject to national emission standards. These recordkeeping
and reporting requirements are specifically authorized by section 114
of the CAA (42 U.S.C. 7414). All information submitted to the EPA
pursuant to the recordkeeping and reporting requirements for which a
claim of confidentiality is made is safeguarded according to agency
policies set forth in 40 CFR part 2, subpart B.
This final rule will require maintenance inspections of the control
devices but will not require any notifications or reports beyond those
required by the General Provisions aside from a notification of intent
to commence burning solid waste materials and notification of
alternative fuel use for those units that are in the Gas 1 subcategory
but burn liquid fuels for periodic testing, or during periods of gas
curtailment or gas supply emergencies. The recordkeeping requirements
require only the specific information needed to determine compliance.
The revised annual monitoring, reporting and recordkeeping burden
for this collection (averaged over the first 3 years after the
effective date of the standards) is estimated to be $95.3 million which
is about the same as estimated for the March 2011 final rule. This
includes 323,130 labor hours per year at a total labor cost of $30.6
million per year, and total non-labor capital costs of $64.7 million
per year. This estimate includes initial and annual performance test,
conducting and documenting an energy assessment, conducting fuel
specifications for Gas 1 units, repeat testing under worst-case
conditions for solid fuel units, conducting and documenting a tune-up,
semiannual excess emission reports, maintenance inspections, developing
a monitoring plan, notifications and recordkeeping. Monitoring,
testing, tune-up and energy assessment costs and cost were also
included in the cost estimates presented in the control costs impacts
estimates in section VI.D of this preamble. The total burden for the
federal government (averaged over the first 3 years after the effective
date of the standard) is estimated to be 100,608 hours per year at a
total labor cost of $5.3 million per year. Burden is defined at 5 CFR
1320.3(b).
An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations in 40 CFR are listed in 40 CFR part 9. In addition,
the EPA is amending the table in 40 CFR part 9 of currently approved
OMB control numbers for various regulations to list the regulatory
citations for the information requirements contained in this final
rule.
C. Regulatory Flexibility Act
The RFA generally requires an agency to prepare a regulatory
flexibility analysis of any rule subject to notice and comment
rulemaking requirements under the Administrative Procedure Act or any
other statute unless the agency certifies that the rule will not have a
significant economic impact on a substantial number of small
entities.\1\ The RFA also allows an agency to ``consider a series of
closely related rules as one rule for the purposes of sections'' 603
(initial regulatory flexibility analysis) and 604 (final regulatory
flexibility analysis) in order to avoid ``duplicative action.'' 5
U.S.C. Sec. 605(c). This final rule is closely related to the final
major source rule, which the EPA signed on February 21, 2011. The EPA
prepared a final regulatory flexibility analyses in connection with the
major source rule. Therefore,
[[Page 7159]]
pursuant to Sec. 605(c), the EPA is not required to complete a final
regulatory flexibility analysis for this rule.
---------------------------------------------------------------------------
\1\ Small entities include small businesses, small
organizations, and small governmental jurisdictions. For purposes of
assessing the impacts of today's rule on small entities, small
entity is defined as: (1) A small business according to Small
Business Administration (SBA) size standards by the North American
Industry Classification System category of the owning entity. The
range of small business size standards for the affected industries
ranges from 500 to 1,000 employees, except for petroleum refining
and electric utilities. In these latter two industries, the size
standard is 1,500 employees and a mass throughput of 75,000 barrels/
day or less, and 4 million kilowatt-hours of production or less,
respectively; (2) a small governmental jurisdiction that is a
government of a city, county, town, school district or special
district with a population of less than 50,000; and (3) a small
organization that is any not-for-profit enterprise which is
independently owned and operated and is not dominant in its field.
---------------------------------------------------------------------------
The EPA has been concerned with potential small entity impacts
since it began developing the major source rule. The EPA conducted
outreach to small entities and, pursuant to Sec. 609 of RFA, convened
a Small Business Advocacy Review Panel to obtain advice and
recommendations from small entity representatives.
Pursuant to the RFA, the EPA used the Panel's report and prepared
both an initial regulatory flexibility analysis and a final regulatory
flexibility analysis in connection with the closely related major
source rule. Convening an additional Panel and preparing an additional
final regulatory flexibility analysis would be procedurally duplicative
and is unnecessary given that the issues here are within the scope of
those considered by the Panel. In addition, this final action would
decrease capital and annualized costs on small entities by about 3
percent and 10 percent, respectively, relative to the closely related
final rule.
D. Unfunded Mandates Reform Act
Title II of the UMRA of 1995, 2 U.S.C. 1531-1538, requires federal
agencies, unless otherwise prohibited by law, to assess the effects of
their regulatory actions on state, local and tribal governments and the
private sector. Federal agencies must also develop a plan to provide
notice to small governments that might be significantly or uniquely
affected by any regulatory requirements. The plan must enable officials
of affected small governments to have meaningful and timely input in
the development of the EPA regulatory proposals with significant
Federal intergovernmental mandates and must inform, educate, and advise
small governments on compliance with the regulatory requirements.
Both this rule and the March 21, 2011 final rule contain a federal
mandate that may result in expenditures of $100 million or more for
state, local and tribal governments, in the aggregate, or the private
sector in any one year. Accordingly, the EPA prepared under section 202
of the UMRA a written statement for the final rule. This final rule
also contains a federal mandate that may result in expenditures of $100
million or more for state, local, and tribal governments, in the
aggregate, or the private sector in any one year. The discussion below
has been updated to reflect the changes.
1. Statutory Authority
As discussed in the March 21, 2011, final rule, the statutory
authority for this final rulemaking is section 112 of the CAA. Title
III of the CAA Amendments was enacted to reduce nationwide air toxic
emissions. Section 112(b) of the CAA lists the 188 chemicals,
compounds, or groups of chemicals deemed by Congress to be HAP. These
toxic air pollutants are to be regulated by NESHAP.
Section 112(d) of the CAA directs us to develop NESHAP which
require existing and new major sources to control emissions of HAP
using MACT based standards. This NESHAP applies to all boilers and
process heaters located at major sources of HAP emissions.
2. Social Costs and Benefits
The regulatory impact analysis prepared for the March 21, 2011
final rule, which we have revised for this final rule, including the
agency's assessment of costs and benefits, is detailed in the
``Regulatory Impact Analysis for the Final Industrial Boilers and
Process Heaters MACT (2011)'' and in the ``Regulatory Impact Results
for the Reconsideration Final Rule for National Emission Standards for
Hazardous Air Pollutants for Industrial, Commercial, and Institutional
Boilers and Process Heaters at Major Sources'' in the docket. Based on
estimated compliance costs associated with this final rule and the
predicted change in prices and production in the affected industries,
the estimated social costs of this rule are $1.4 to 1.6 billion (2008
dollars).
It is estimated that 3 years after implementation of this final
rule, HAP would be reduced by 45,000 tpy, including reductions in HCl,
hydrogen fluoride, metallic HAP including mercury, and several other
organic HAP from boilers and process heaters. Studies have determined a
relationship between exposure to these HAP and the onset of cancer,
however, the agency is unable to provide a monetized estimate of the
HAP benefits at this time. In addition, there are significant annual
reductions in fine particulate matter (PM2.5) and in
SO2 that would occur, including 25 thousand tons of
PM2.5 and 558 thousand tons of SO2. These
reductions occur within 3 years after the implementation of the final
regulation and are expected to continue throughout the life of the
affected sources. The major health effect associated with reducing
PM2.5 and PM2.5 precursors (such as
SO2) are a reduction in premature mortality. Other health
effects associated with PM2.5 emission reductions include
avoiding cases of chronic bronchitis, heart attacks, asthma attacks and
work-lost days (i.e., days when employees are unable to work). While we
are unable to monetize the benefits associated with the HAP emissions
reductions, we are able to monetize the benefits associated with the
PM2.5 and SO2 emissions reductions. For
SO2 and PM2.5, we estimated the benefits
associated with health effects of PM but were unable to quantify all
categories of benefits (particularly those associated with ecosystem
and visibility effects). Our estimates of the monetized benefits in
2015 associated with the implementation of the final regulatory action
range from $27 billion (2008 dollars) to $67 billion (2008 dollars)
when using a 3 percent discount rate (or from $25 billion (2008
dollars) to $61 billion (2008 dollars) when using a 7 percent discount
rate). This estimate, at a 3 percent discount rate, is about $25
billion (2008 dollars) to $65 billion (2008 dollars) higher than the
estimated social costs shown earlier in this section. The general
approach used to value benefits is discussed in more detail earlier in
this preamble. For more detailed information on the benefits estimated
for the rulemaking, refer to the RIA and the memos updating the impacts
and benefits in the docket.
3. Future and Disproportionate Costs
The UMRA requires that we estimate, where accurate estimation is
reasonably feasible, future compliance costs imposed by this final rule
and any disproportionate budgetary effects. Our estimates of the future
compliance costs of the rule are discussed previously in this preamble.
We do not believe that there will be any disproportionate budgetary
effects of this final rule on any particular areas of the country,
state or local governments, types of communities (e.g., urban, rural)
or particular industry segments. See the results of the ``Regulatory
Impact Analysis for the Final Industrial Boilers and Process Heaters
MACT (2011).''
4. Effects on the National Economy
The UMRA requires that we estimate the effect of this final rule on
the national economy. To the extent feasible, we must estimate the
effect on productivity, economic growth, full employment, creation of
productive jobs and international competitiveness of the U.S. goods and
services, if we determine that accurate estimates are reasonably
feasible and that such effect is relevant and material.
The nationwide economic impact of this final rule is presented in
the
[[Page 7160]]
``Regulatory Impact Analysis for the Final Industrial Boilers and
Process Heaters MACT (2011)'' and a memoranda that are included in the
docket, entitled ``Regulatory Impact Results for the Reconsideration
Final Rule for National Emission Standards for Hazardous Air Pollutants
for Industrial, Commercial, and Institutional Boilers and Process
Heaters at Major Sources which update the RIA analyses. This analysis
provides estimates of the effect of this rule on some of the categories
mentioned above. The results of the economic impact analysis are
summarized previously in this preamble. The results show that there
will be a small impact on prices and output, and little impact on
communities that may be affected by this final rule. In addition, there
should be little impact on energy markets (in this case, coal, natural
gas, petroleum products and electricity). Hence, the potential impacts
on the categories mentioned above should be small.
5. Consultation With Government Officials
The UMRA requires that we describe the extent of the agency's prior
consultation with affected state, local and tribal officials, summarize
the officials' comments or concerns, and summarize our response to
those comments or concerns. In addition, section 203 of the UMRA
requires that we develop a plan for informing and advising small
governments that may be significantly or uniquely impacted by a final
rule. We consulted with state and local air pollution control officials
during the development of the final rule. We have also held meetings on
this final rule with many of the stakeholders from numerous individual
companies, institutions, environmental groups, consultants and vendors,
labor unions and other interested parties. We have added materials to
the docket to document these meetings.
Consistent with section 205, the EPA has identified and considered
a reasonable number of regulatory alternatives. Additional information
on the costs and environmental impacts of these regulatory alternatives
is presented in the docket.
The regulatory alternative upon which the emission limits in this
final rule are based represents the MACT floors for all subcategories
and, as a result, it is the least costly and least burdensome
alternative.
This rule is not subject to the requirements of section 203 of UMRA
because it contains no regulatory requirements that might significantly
or uniquely affect small governments. While some small governments may
have some sources affected by this final rule, the impacts are not
expected to be significant. Therefore, this final rule is not subject
to the requirements of section 203 of the UMRA.
E. Executive Order 13132: Federalism
This action does not have federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various levels of government, as
specified in Executive Order 13132. This final rule will not impose
direct compliance costs on state or local governments, and will not
preempt state law. Thus, Executive Order 13132 does not apply to this
action.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). It will not have
substantial direct effects on tribal governments, on the relationship
between the federal government and Indian tribes, or on the
distribution of power and responsibilities between the federal
government and Indian tribes, as specified in Executive Order 13175.
Thus, Executive Order 13175 does not apply to this action.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
The EPA interprets Executive Order 13045 (62 FR 19885, April 23,
1997) as applying to those regulatory actions that concern health or
safety risks, such that the analysis required under section 5-501 of
the Order has the potential to influence the regulation. This action is
not subject to EO 13045 because it is based solely on technology
performance.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This action is not a ``significant energy action'' as defined in
Executive Order 13211 (66 FR 28355, May 22, 2001), because it is not
likely to have a significant adverse effect on the supply,
distribution, or use of energy. For the March 21, 2011, final rule, we
estimated a 0.05 percent price increase for the energy sector and a -
0.02 percent percentage change in production. We estimated a 0.09
percent increase in energy imports. For more information on the
estimated energy effects, please refer to the ``Regulatory Impact
Analysis for the Final Industrial Boilers and Process Heaters MACT
(2011).'' The analysis is available in the public docket. While we did
not recreate the RIA for this final action, the energy impacts for
existing sources decreased slightly, and the energy impacts for new
source increased due to the increased number of new sources that is now
projected. Overall, the projected energy use increased slightly but
would not change the analysis that was conducted for the previous final
rule. Therefore, we conclude that this final rule when implemented is
not likely to have a significant adverse effect on the supply,
distribution, or use of energy.
I. National Technology Transfer and Advancement Act
Section 12(d) of the NTTAA, Public Law 104-113, 12(d) (15 U.S.C.
272 note) directs the EPA to use VCS in its regulatory activities
unless to do so would be inconsistent with applicable law or otherwise
impractical. VCS are technical standards (e.g., materials
specifications, test methods, sampling procedures, and business
practices) that are developed or adopted by VCS bodies. NTTAA directs
the EPA to provide Congress, through the OMB, explanations when the
agency decides not to use available and applicable VCS.
This action does not involve any new technical standards from those
contained in the March 21, 2011 final rule. Therefore, the EPA did not
consider the use of any VCS. See 76 FR 15660-15662 for the NTTAA
discussion in the March 21, 2011 final rule.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
For the March 2011 final rule, the EPA determined that the rule
would not have disproportionately high and adverse human health or
environmental effects on minority or low-income populations because it
increases the
[[Page 7161]]
level of environmental protection for all affected populations without
having any disproportionately high and adverse human health or
environmental effects on any population, including any minority or low-
income population. Compared to the previous final rule, while the
amendments are somewhat less stringent for some subcategories of units
and more stringent for some others, the overall increased health
benefits demonstrate that the conclusions from the environmental
justice analysis conducted for the previous final rule are still valid.
Therefore, the EPA has determined this final rule will not have
disproportionately high and adverse human or environmental effects on
minority or low-income populations.
K. Congressional Review Act
The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
United States. EPA will submit a report containing this final rule and
other required information to the U.S. Senate, the U.S. House of
Representatives, and the Comptroller General of the United States prior
to publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is a ``major rule'' as defined by 5 U.S.C.
804(2). With the exception of the May 18, 2011 (76 FR 28661), delay of
the effective date revising subpart DDDDD at 76 FR 15451 (March 21,
2011) being lifted January 31, 2013, this rule will be effective April
1, 2013.
List of Subjects in 40 CFR Part 63
Environmental protection, Administrative practice and procedure,
Air pollution control, Hazardous substances, Incorporation by
reference, Intergovernmental relations, Reporting and Recordkeeping
requirements.
Dated: December 20, 2012
Lisa P. Jackson,
Administrator.
For the reasons cited in the preamble, title 40, chapter I, part 63
of the Code of Federal Regulations is amended as follows:
PART 63--[AMENDED]
0
1. The authority for part 63 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
0
2. Effective January 31, 2013, the May 18, 2011 (76 FR 28661), delay of
the effective date revising subpart DDDDD at 76 FR 15451 (March 21,
2011) is lifted.
Subpart A--[Amended]
0
3. Section 63.14 is amended by:
0
a. Revising paragraphs (b)(19), (b)(23), (b)(35), (b)(40), (b)(69), and
(b)(70).
0
b. Removing and reserving paragraph (b)(53).
0
c. Adding paragraphs (b)(46), (b)(55), and (b)(76) through (83).
0
d. Adding paragraphs (p)(12) through (20).
0
e. Adding paragraph (r).
The revisions and additions read as follows:
Sec. 63.14 Incorporations by reference.
* * * * *
(b) * * *
(19) ASTM D95-05 (Reapproved 2010), Standard Test Method for Water
in Petroleum Products and Bituminous Materials by Distillation,
approved May 1, 2010, IBR approved for Sec. 63.10005(i) and table 6 to
subpart DDDDD.
* * * * *
(23) ASTM D4006-11, Standard Test Method for Water in Crude Oil by
Distillation, including Annex A1 and Appendix X1, approved June 1,
2011, IBR approved for Sec. 63.10005(i) and table 6 to subpart DDDDD.
* * * * *
(35) ASTM D6784-02 (Reapproved 2008) Standard Test Method for
Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas
Generated from Coal-Fired Stationary Sources (Ontario Hydro Method),
approved April 1, 2008, IBR approved for table 1 to subpart DDDDD of
this part, table 2 to subpart DDDDD of this part, table 5 to subpart
DDDDD, table 11 to subpart DDDDD of this part, table 12 to subpart
DDDDD of this part, table 13 to subpart DDDDD of this part, and table 4
to subpart JJJJJJ of this part.
* * * * *
(40) ASTM D396-10 Standard Specification for Fuel Oils, approved
October 1, 2010, IBR approved for Sec. 63.7575 and Sec. 63.11237.
* * * * *
(46) ASTM D4606-03 (2007), Standard Test Method for Determination
of Arsenic and Selenium in Coal by the Hydride Generation/Atomic
Absorption Method, approved October 1, 2007, IBR approved for table 6
to subpart DDDDD.
* * * * *
(55) ASTM D6357-11, Test Methods for Determination of Trace
Elements in Coal, Coke, and Combustion Residues from Coal Utilization
Processes by Inductively Coupled Plasma Atomic Emission Spectrometry,
approved April 1, 2011, IBR approved for table 6 to subpart DDDDD.
* * * * *
(69) ASTM D4057-06 (Reapproved 2011), Standard Practice for Manual
Sampling of Petroleum and Petroleum Products, including Annex A1,
approved June 1, 2011, IBR approved for Sec. 63.10005(i) and table 6
to subpart DDDDD.
(70) ASTM D4177-95 (Reapproved 2010), Standard Practice for
Automatic Sampling of Petroleum and Petroleum Products, including
Annexes A1 through A6 and Appendices X1 and X2, approved May 1, 2010,
IBR approved for Sec. 63.10005(i) and table 6 to subpart DDDDD.
* * * * *
(76) ASTM D6751-11b, Standard Specification for Biodiesel Fuel
Blend Stock (B100) for Middle Distillate Fuels, approved July 15, 2011,
IBR approved for Sec. 63.7575 and Sec. 63.11237.
(77) ASTM D975-11b, Standard Specification for Diesel Fuel Oils,
approved December 1, 2011, IBR approved for Sec. 63.7575.
(78) ASTM D5864-11 Standard Test Method for Determining Aerobic
Aquatic Biodegradation of Lubricants or Their Components, approved
March 1, 2011, IBR approved for table 6 to subpart DDDDD.
(79) ASTM D240-09 Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter, approved July 1, 2009,
IBR approved for table 6 to subpart DDDDD.
(80) ASTM D4208-02 (2007) Standard Test Method for Total Chlorine
in Coal by the Oxygen Bomb Combustion/Ion Selective Electrode Method,
approved May 1, 2007, IBR approved for table 6 to subpart DDDDD.
(81) ASTM D5192-09 Standard Practice for Collection of Coal Samples
from Core, approved June 1, 2009, IBR approved for table 6 to subpart
DDDDD.
(82) ASTM D7430-11ae1, Standard Practice for Mechanical Sampling of
Coal, approved October 1, 2011, IBR approved for table 6 to subpart
DDDDD.
(83) ASTM D6883-04, Standard Practice for Manual Sampling of
Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles,
approved June 1, 2004, IBR approved for table 6 to subpart DDDDD.
* * * * *
(p) * * *
(12) Method 5050 (SW-846-5050), Bomb Preparation Method for Solid
Waste, Revision 0, September 1994, in
[[Page 7162]]
EPA Publication No. SW-846, Test Methods for Evaluating Solid Waste,
Physical/Chemical Methods, Third Edition IBR approved for table 6 to
subpart DDDDD.
(13) Method 9056 (SW-846-9056), Determination of Inorganic Anions
by Ion Chromatography, Revision 1, February 2007, in EPA Publication
No. SW-846, Test Methods for Evaluating Solid Waste, Physical/Chemical
Methods, Third Edition, IBR approved for table 6 to subpart DDDDD.
(14) Method 9076 (SW-846-9076), Test Method for Total Chlorine in
New and Used Petroleum Products by Oxidative Combustion and
Microcoulometry, Revision 0, September 1994, in EPA Publication No. SW-
846, Test Methods for Evaluating Solid Waste, Physical/Chemical
Methods, Third Edition, IBR approved for table 6 to subpart DDDDD.
(15) Method 1631 Revision E, Mercury in Water by Oxidation, Purge
and Trap, and Cold Vapor Atomic Absorption Fluorescence Spectrometry,
Revision E, EPA-821-R-02-019, August 2002, IBR approved for table 6 to
subpart DDDDD.
(16) Method 200.8, Determination of Trace Elements in Waters and
Wastes by Inductively Coupled Plasma--Mass Spectrometry, Revision 5.4,
1994, IBR approved for table 6 to subpart DDDDD.
(17) Method 6020A (SW-846-6020A), Inductively Coupled Plasma-Mass
Spectrometry, Revision 1, February 2007, in EPA Publication No. SW-846,
Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,
Third Edition, IBR approved for table 6 to subpart DDDDD.
(18) Method 6010C (SW-846-6010C), Inductively Coupled Plasma-Atomic
Emission Spectrometry, Revision 3, February 2007, in EPA Publication
No. SW-846, Test Methods for Evaluating Solid Waste, Physical/Chemical
Methods, Third Edition, IBR approved for table 6 to subpart DDDDD.
(19) Method 7060A (SW-846-7060A), Arsenic (Atomic Absorption,
Furnace Technique), Revision 1, September 1994, in EPA Publication No.
SW-846, Test Methods for Evaluating Solid Waste, Physical/Chemical
Methods, Third Edition, IBR approved for table 6 to subpart DDDDD.
(20) Method 7740 (SW-846-7740), Selenium (Atomic Absorption,
Furnace Technique), Revision 0, September 1986, in EPA Publication No.
SW-846, Test Methods for Evaluating Solid Waste, Physical/Chemical
Methods, Third Edition, IBR approved for table 6 to subpart DDDDD.
* * * * *
(r) The following material is available for purchase from the
Technical Association of the Pulp and Paper Industry (TAPPI), 15
Technology Parkway South, Norcross, GA 30092, (800) 332-8686, https://www.tappi.org.
(1) TAPPI T 266, Determination of Sodium, Calcium, Copper, Iron,
and Manganese in Pulp and Paper by Atomic Absorption Spectroscopy
(Reaffirmation of T 266 om-02), Draft No. 2, July 2006, IBR approved
for table 6 to subpart DDDDD.
(2) [Reserved]
Subpart DDDDD--[Amended]
0
4. Section 63.7485 is revised to read as follows:
Sec. 63.7485 Am I subject to this subpart?
You are subject to this subpart if you own or operate an
industrial, commercial, or institutional boiler or process heater as
defined in Sec. 63.7575 that is located at, or is part of, a major
source of HAP, except as specified in Sec. 63.7491. For purposes of
this subpart, a major source of HAP is as defined in Sec. 63.2, except
that for oil and natural gas production facilities, a major source of
HAP is as defined in Sec. 63.7575.
0
5. Section 63.7490 is amended by adding paragraph (e) to read as
follows:
Sec. 63.7490 What is the affected source of this subpart?
* * * * *
(e) An existing electric utility steam generating unit (EGU) that
meets the applicability requirements of this subpart after the
effective date of this final rule due to a change (e.g., fuel switch)
is considered to be an existing source under this subpart.
0
6. Section 63.7491 is amended by:
0
a. Revising the introductory text.
0
b. Revising paragraph (a).
0
c. Revising paragraph (c).
0
d. Revising paragraph (h)
0
e. Revising paragraph (i).
0
f. Revising paragraph (m).
0
g. Revising paragraph (n).
The revisions read as follows:
Sec. 63.7491 Are any boilers or process heaters not subject to this
subpart?
The types of boilers and process heaters listed in paragraphs (a)
through (n) of this section are not subject to this subpart.
(a) An electric utility steam generating unit (EGU) covered by
subpart UUUUU of this part.
* * * * *
(c) A boiler or process heater that is used specifically for
research and development, including test steam boilers used to provide
steam for testing the propulsion systems on military vessels. This does
not include units that provide heat or steam to a process at a research
and development facility.
* * * * *
(h) Any boiler or process heater that is part of the affected
source subject to another subpart of this part, such as boilers and
process heaters used as control devices to comply with subparts JJJ,
OOO, PPP, and U of this part.
(i) Any boiler or process heater that is used as a control device
to comply with another subpart of this part, or part 60, part 61, or
part 65 of this chapter provided that at least 50 percent of the
average annual heat input during any 3 consecutive calendar years to
the boiler or process heater is provided by regulated gas streams that
are subject to another standard.
* * * * *
(m) A unit that burns hazardous waste covered by Subpart EEE of
this part. A unit that is exempt from Subpart EEE as specified in Sec.
63.1200(b) is not covered by Subpart EEE.
(n) Residential boilers as defined in this subpart.
* * * * *
0
7. Section 63.7495 is amended by:
0
a. Revising paragraph (a).
0
b. Revising paragraph (b).
0
c. Adding paragraphs (e), (f), and (g).
The revisions and additions read as follows:
Sec. 63.7495 When do I have to comply with this subpart?
(a) If you have a new or reconstructed boiler or process heater,
you must comply with this subpart by January 31, 2013, or upon startup
of your boiler or process heater, whichever is later.
(b) If you have an existing boiler or process heater, you must
comply with this subpart no later than January 31, 2016, except as
provided in Sec. 63.6(i).
* * * * *
(e) If you own or operate an industrial, commercial, or
institutional boiler or process heater and would be subject to this
subpart except for the exemption in Sec. 63.7491(l) for commercial and
industrial solid waste incineration units covered by part 60, subpart
CCCC or subpart DDDD, and you cease combusting solid waste, you must be
in compliance with this subpart and are no longer subject to part 60,
subparts CCCC or DDDD beginning on the effective date of the switch as
identified under the provisions of Sec. 60.2145(a)(2) and (3) or Sec.
60.2710(a)(2) and (3).
(f) If you own or operate an existing EGU that becomes subject to
this subpart after January 31, 2013, you must
[[Page 7163]]
be in compliance with the applicable existing source provisions of this
subpart on the effective date such unit becomes subject to this
subpart.
(g) If you own or operate an existing industrial, commercial, or
institutional boiler or process heater and would be subject to this
subpart except for a exemption in Sec. 63.7491(i) that becomes subject
to this subpart after January 31, 2013, you must be in compliance with
the applicable existing source provisions of this subpart within 3
years after such unit becomes subject to this subpart.
0
8.Section 63.7499 is amended by revising paragraphs (d) and (f) through
(l) and adding paragraphs (p) through (u) to read as follows:
Sec. 63.7499 What are the subcategories of boilers and process
heaters?
* * * * *
(d) Stokers/sloped grate/other units designed to burn kiln dried
biomass/bio-based solid.
* * * * *
(f) Suspension burners designed to burn biomass/bio-based solid.
(g) Fuel cells designed to burn biomass/bio-based solid.
(h) Hybrid suspension/grate burners designed to burn wet biomass/
bio-based solid.
(i) Stokers/sloped grate/other units designed to burn wet biomass/
bio-based solid.
(j) Dutch ovens/pile burners designed to burn biomass/bio-based
solid.
(k) Units designed to burn liquid fuel that are non-continental
units.
(l) Units designed to burn gas 1 fuels.
* * * * *
(p) Units designed to burn solid fuel.
(q) Units designed to burn liquid fuel.
(r) Units designed to burn coal/solid fossil fuel.
(s) Fluidized bed units with an integrated fluidized bed heat
exchanger designed to burn coal/solid fossil fuel.
(t) Units designed to burn heavy liquid fuel.
(u) Units designed to burn light liquid fuel.
0
9. Section 63.7500 is amended by:
0
a. Revising paragraph (a).
0
b. Revising paragraph (c).
0
c. Adding paragraph (d).
0
d. Adding paragraph (e).
0
e. Adding paragraph (f).
Sec. 63.7500 What emission limitations, work practice standards, and
operating limits must I meet?
(a) You must meet the requirements in paragraphs (a)(1) through (3)
of this section, except as provided in paragraphs (b), through (e) of
this section. You must meet these requirements at all times the
affected unit is operating, except as provided in paragraph (f) of this
section.
(1) You must meet each emission limit and work practice standard in
Tables 1 through 3, and 11 through 13 to this subpart that applies to
your boiler or process heater, for each boiler or process heater at
your source, except as provided under Sec. 63.7522. The output-based
emission limits, in units of pounds per million Btu of steam output, in
Tables 1 or 2 to this subpart are an alternative applicable only to
boilers and process heaters that generate steam. The output-based
emission limits, in units of pounds per megawatt-hour, in Tables 1 or 2
to this subpart are an alternative applicable only to boilers that
generate electricity. If you operate a new boiler or process heater,
you can choose to comply with alternative limits as discussed in
paragraphs (a)(1)(i) through (a)(1)(iii) of this section, but on or
after January 31, 2016, you must comply with the emission limits in
Table 1 to this subpart.
(i) If your boiler or process heater commenced construction or
reconstruction after June 4, 2010 and before May 20, 2011, you may
comply with the emission limits in Table 1 or 11 to this subpart until
January 31, 2016.
(ii) If your boiler or process heater commenced construction or
reconstruction after May 20, 2011 and before December 23, 2011, you may
comply with the emission limits in Table 1 or 12 to this subpart until
January 31, 2016.
(iii) If your boiler or process heater commenced construction or
reconstruction after December 23, 2011 and before January 31, 2013, you
may comply with the emission limits in Table 1 or 13 to this subpart
until January 31, 2016.
(2) You must meet each operating limit in Table 4 to this subpart
that applies to your boiler or process heater. If you use a control
device or combination of control devices not covered in Table 4 to this
subpart, or you wish to establish and monitor an alternative operating
limit or an alternative monitoring parameter, you must apply to the EPA
Administrator for approval of alternative monitoring under Sec.
63.8(f).
(3) At all times, you must operate and maintain any affected source
(as defined in Sec. 63.7490), including associated air pollution
control equipment and monitoring equipment, in a manner consistent with
safety and good air pollution control practices for minimizing
emissions. Determination of whether such operation and maintenance
procedures are being used will be based on information available to the
Administrator that may include, but is not limited to, monitoring
results, review of operation and maintenance procedures, review of
operation and maintenance records, and inspection of the source.
* * * * *
(c) Limited-use boilers and process heaters must complete a tune-up
every 5 years as specified in Sec. 63.7540. They are not subject to
the emission limits in Tables 1 and 2 or 11 through 13 to this subpart,
the annual tune-up, or the energy assessment requirements in Table 3 to
this subpart, or the operating limits in Table 4 to this subpart.
(d) Boilers and process heaters with a heat input capacity of less
than or equal to 5 million Btu per hour in the units designed to burn
gas 2 (other) fuels subcategory or units designed to burn light liquid
fuels subcategory must complete a tune-up every 5 years as specified in
Sec. 63.7540.
(e) Boilers and process heaters in the units designed to burn gas 1
fuels subcategory with a heat input capacity of less than or equal to 5
million Btu per hour must complete a tune-up every 5 years as specified
in Sec. 63.7540. Boilers and process heaters in the units designed to
burn gas 1 fuels subcategory with a heat input capacity greater than 5
million Btu per hour and less than 10 million Btu per hour must
complete a tune-up every 2 years as specified in Sec. 63.7540. Boilers
and process heaters in the units designed to burn gas 1 fuels
subcategory are not subject to the emission limits in Tables 1 and 2 or
11 through 13 to this subpart, or the operating limits in Table 4 to
this subpart.
(f) These standards apply at all times the affected unit is
operating, except during periods of startup and shutdown during which
time you must comply only with Table 3 to this subpart.
0
10. Section 63.7501 is revised to read as follows:
Sec. 63.7501 Affirmative Defense for Violation of Emission Standards
During Malfunction.
In response to an action to enforce the standards set forth in
Sec. 63.7500 you may assert an affirmative defense to a claim for
civil penalties for violations of such standards that are caused by
malfunction, as defined at Sec. 63.2. Appropriate penalties may be
assessed if you fail to meet your burden of proving all of the
requirements in the affirmative defense. The affirmative defense shall
not be available for claims for injunctive relief.
(a) Assertion of affirmative defense. To establish the affirmative
defense in
[[Page 7164]]
any action to enforce such a standard, you must timely meet the
reporting requirements in paragraph (b) of this section, and must prove
by a preponderance of evidence that:
(1) The violation:
(i) Was caused by a sudden, infrequent, and unavoidable failure of
air pollution control equipment, process equipment, or a process to
operate in a normal or usual manner; and
(ii) Could not have been prevented through careful planning, proper
design, or better operation and maintenance practices; and
(iii) Did not stem from any activity or event that could have been
foreseen and avoided, or planned for; and
(iv) Was not part of a recurring pattern indicative of inadequate
design, operation, or maintenance; and
(2) Repairs were made as expeditiously as possible when a violation
occurred; and
(3) The frequency, amount, and duration of the violation (including
any bypass) were minimized to the maximum extent practicable; and
(4) If the violation resulted from a bypass of control equipment or
a process, then the bypass was unavoidable to prevent loss of life,
personal injury, or severe property damage; and
(5) All possible steps were taken to minimize the impact of the
violation on ambient air quality, the environment, and human health;
and
(6) All emissions monitoring and control systems were kept in
operation if at all possible, consistent with safety and good air
pollution control practices; and
(7) All of the actions in response to the violation were documented
by properly signed, contemporaneous operating logs; and
(8) At all times, the affected source was operated in a manner
consistent with good practices for minimizing emissions; and
(9) A written root cause analysis has been prepared, the purpose of
which is to determine, correct, and eliminate the primary causes of the
malfunction and the violation resulting from the malfunction event at
issue. The analysis shall also specify, using best monitoring methods
and engineering judgment, the amount of any emissions that were the
result of the malfunction.
(b) Report. The owner or operator seeking to assert an affirmative
defense shall submit a written report to the Administrator with all
necessary supporting documentation, that it has met the requirements
set forth in Sec. 63.7500 of this section. This affirmative defense
report shall be included in the first periodic compliance, deviation
report or excess emission report otherwise required after the initial
occurrence of the violation of the relevant standard (which may be the
end of any applicable averaging period). If such compliance, deviation
report or excess emission report is due less than 45 days after the
initial occurrence of the violation, the affirmative defense report may
be included in the second compliance, deviation report or excess
emission report due after the initial occurrence of the violation of
the relevant standard.
0
11. Section 63.7505 is amended by:
0
a. Revising paragraph (a).
0
b. Revising paragraph (c).
0
c. Revising paragraphs (d) introductory text, (d)(1) introductory text,
and (d)(1)(iii).
Sec. 63.7505 What are my general requirements for complying with this
subpart?
(a) You must be in compliance with the emission limits, work
practice standards, and operating limits in this subpart. These limits
apply to you at all times the affected unit is operating except for the
periods noted in Sec. 63.7500(f).
* * * * *
(c) You must demonstrate compliance with all applicable emission
limits using performance stack testing, fuel analysis, or continuous
monitoring systems (CMS), including a continuous emission monitoring
system (CEMS), continuous opacity monitoring system (COMS), continuous
parameter monitoring system (CPMS), or particulate matter continuous
parameter monitoring system (PM CPMS), where applicable. You may
demonstrate compliance with the applicable emission limit for hydrogen
chloride (HCl), mercury, or total selected metals (TSM) using fuel
analysis if the emission rate calculated according to Sec. 63.7530(c)
is less than the applicable emission limit. (For gaseous fuels, you may
not use fuel analyses to comply with the TSM alternative standard or
the HCl standard.) Otherwise, you must demonstrate compliance for HCl,
mercury, or TSM using performance testing, if subject to an applicable
emission limit listed in Tables 1, 2, or 11 through 13 to this subpart.
(d) If you demonstrate compliance with any applicable emission
limit through performance testing and subsequent compliance with
operating limits (including the use of CPMS), or with a CEMS, or COMS,
you must develop a site-specific monitoring plan according to the
requirements in paragraphs (d)(1) through (4) of this section for the
use of any CEMS, COMS, or CPMS. This requirement also applies to you if
you petition the EPA Administrator for alternative monitoring
parameters under Sec. 63.8(f).
(1) For each CMS required in this section (including CEMS, COMS, or
CPMS), you must develop, and submit to the Administrator for approval
upon request, a site-specific monitoring plan that addresses design,
data collection, and the quality assurance and quality control elements
outlined in Sec. 63.8(d) and the elements described in paragraphs
(d)(1)(i) through (iii) of this section. You must submit this site-
specific monitoring plan, if requested, at least 60 days before your
initial performance evaluation of your CMS. This requirement to develop
and submit a site specific monitoring plan does not apply to affected
sources with existing CEMS or COMS operated according to the
performance specifications under appendix B to part 60 of this chapter
and that meet the requirements of Sec. 63.7525. Using the process
described in Sec. 63.8(f)(4), you may request approval of alternative
monitoring system quality assurance and quality control procedures in
place of those specified in this paragraph and, if approved, include
the alternatives in your site-specific monitoring plan.
* * * * *
(iii) Performance evaluation procedures and acceptance criteria
(e.g., calibrations, accuracy audits, analytical drift).
* * * * *
0
12. Section 63.7510 is revised to read as follows:
Sec. 63.7510 What are my initial compliance requirements and by what
date must I conduct them?
(a) For each boiler or process heater that is required or that you
elect to demonstrate compliance with any of the applicable emission
limits in Tables 1 or 2 or 11 through 13 of this subpart through
performance testing, your initial compliance requirements include all
the following:
(1) Conduct performance tests according to Sec. 63.7520 and Table
5 to this subpart.
(2) Conduct a fuel analysis for each type of fuel burned in your
boiler or process heater according to Sec. 63.7521 and Table 6 to this
subpart, except as specified in paragraphs (a)(2)(i) through (iii) of
this section.
(i) For each boiler or process heater that burns a single type of
fuel, you are not required to conduct a fuel analysis for each type of
fuel burned in your boiler or process heater according to
[[Page 7165]]
Sec. 63.7521 and Table 6 to this subpart. For purposes of this
subpart, units that use a supplemental fuel only for startup, unit
shutdown, and transient flame stability purposes still qualify as units
that burn a single type of fuel, and the supplemental fuel is not
subject to the fuel analysis requirements under Sec. 63.7521 and Table
6 to this subpart.
(ii) When natural gas, refinery gas, or other gas 1 fuels are co-
fired with other fuels, you are not required to conduct a fuel analysis
of those fuels according to Sec. 63.7521 and Table 6 to this subpart.
If gaseous fuels other than natural gas, refinery gas, or other gas 1
fuels are co-fired with other fuels and those gaseous fuels are subject
to another subpart of this part, part 60, part 61, or part 65, you are
not required to conduct a fuel analysis of those fuels according to
Sec. 63.7521 and Table 6 to this subpart.
(iii) You are not required to conduct a chlorine fuel analysis for
any gaseous fuels. You must conduct a fuel analysis for mercury on
gaseous fuels unless the fuel is exempted in paragraphs (a)(2)(i) and
(ii) of this section.
(3) Establish operating limits according to Sec. 63.7530 and Table
7 to this subpart.
(4) Conduct CMS performance evaluations according to Sec. 63.7525.
(b) For each boiler or process heater that you elect to demonstrate
compliance with the applicable emission limits in Tables 1 or 2 or 11
through 13 to this subpart for HCl, mercury, or TSM through fuel
analysis, your initial compliance requirement is to conduct a fuel
analysis for each type of fuel burned in your boiler or process heater
according to Sec. 63.7521 and Table 6 to this subpart and establish
operating limits according to Sec. 63.7530 and Table 8 to this
subpart. The fuels described in paragraph (a)(2)(i) and (ii) of this
section are exempt from these fuel analysis and operating limit
requirements. The fuels described in paragraph (a)(2)(ii) of this
section are exempt from the chloride fuel analysis and operating limit
requirements. Boilers and process heaters that use a CEMS for mercury
or HCl are exempt from the performance testing and operating limit
requirements specified in paragraph (a) of this section for the HAP for
which CEMS are used.
(c) If your boiler or process heater is subject to a carbon
monoxide (CO) limit, your initial compliance demonstration for CO is to
conduct a performance test for CO according to Table 5 to this subpart
or conduct a performance evaluation of your continuous CO monitor, if
applicable, according to Sec. 63.7525(a). Boilers and process heaters
that use a CO CEMS to comply with the applicable alternative CO CEMS
emission standard listed in Tables 12, or 11 through 13 to this
subpart, as specified in Sec. 63.7525(a), are exempt from the initial
CO performance testing and oxygen concentration operating limit
requirements specified in paragraph (a) of this section.
(d) If your boiler or process heater is subject to a PM limit, your
initial compliance demonstration for PM is to conduct a performance
test in accordance with Sec. 63.7520 and Table 5 to this subpart.
(e) For existing affected sources (as defined in Sec. 63.7490),
you must complete the initial compliance demonstration, as specified in
paragraphs (a) through (d) of this section, no later than 180 days
after the compliance date that is specified for your source in Sec.
63.7495 and according to the applicable provisions in Sec. 63.7(a)(2)
as cited in Table 10 to this subpart, except as specified in paragraph
(j) of this section. You must complete an initial tune-up by following
the procedures described in Sec. 63.7540(a)(10)(i) through (vi) no
later than the compliance date specified in Sec. 63.7495, except as
specified in paragraph (j) of this section. You must complete the one-
time energy assessment specified in Table 3 to this subpart no later
than the compliance date specified in Sec. 63.7495, except as
specified in paragraph (j) of this section.
(f) For new or reconstructed affected sources (as defined in Sec.
63.7490), you must complete the initial compliance demonstration with
the emission limits no later than July 30, 2013 or within 180 days
after startup of the source, whichever is later. If you are
demonstrating compliance with an emission limit in Tables 11 through 13
to this subpart that is less stringent (that is, higher) than the
applicable emission limit in Table 1 to this subpart, you must
demonstrate compliance with the applicable emission limit in Table 1 no
later than July 29, 2016.
(g) For new or reconstructed affected sources (as defined in Sec.
63.7490), you must demonstrate initial compliance with the applicable
work practice standards in Table 3 to this subpart within the
applicable annual, biennial, or 5-year schedule as specified in Sec.
63.7540(a) following the initial compliance date specified in Sec.
63.7495(a). Thereafter, you are required to complete the applicable
annual, biennial, or 5-year tune-up as specified in Sec. 63.7540(a).
(h) For affected sources (as defined in Sec. 63.7490) that ceased
burning solid waste consistent with Sec. 63.7495(e) and for which the
initial compliance date has passed, you must demonstrate compliance
within 60 days of the effective date of the waste-to-fuel switch. If
you have not conducted your compliance demonstration for this subpart
within the previous 12 months, you must complete all compliance
demonstrations for this subpart before you commence or recommence
combustion of solid waste.
(i) For an existing EGU that becomes subject after January 31,
2013, you must demonstrate compliance within 180 days after becoming an
affected source.
(j) For existing affected sources (as defined in Sec. 63.7490)
that have not operated between the effective date of the rule and the
compliance date that is specified for your source in Sec. 63.7495, you
must complete the initial compliance demonstration, if subject to the
emission limits in Table 2 to this subpart, as specified in paragraphs
(a) through (d) of this section, no later than 180 days after the re-
start of the affected source and according to the applicable provisions
in Sec. 63.7(a)(2) as cited in Table 10 to this subpart. You must
complete an initial tune-up by following the procedures described in
Sec. 63.7540(a)(10)(i) through (vi) no later than 30 days after the
re-start of the affected source and, if applicable, complete the one-
time energy assessment specified in Table 3 to this subpart, no later
than the compliance date specified in Sec. 63.7495.
0
13. Section 63.7515 is revised to read as follows:
Sec. 63.7515 When must I conduct subsequent performance tests, fuel
analyses, or tune-ups?
(a) You must conduct all applicable performance tests according to
Sec. 63.7520 on an annual basis, except as specified in paragraphs (b)
through (e), (g), and (h) of this section. Annual performance tests
must be completed no more than 13 months after the previous performance
test, except as specified in paragraphs (b) through (e), (g), and (h)
of this section.
(b) If your performance tests for a given pollutant for at least 2
consecutive years show that your emissions are at or below 75 percent
of the emission limit (or, in limited instances as specified in Tables
1 and 2 or 11 through 13 to this subpart, at or below the emission
limit) for the pollutant, and if there are no changes in the operation
of the individual boiler or process heater or air pollution control
equipment that could increase emissions, you may choose to conduct
performance tests for the pollutant every third year. Each such
performance test must be conducted no more than 37 months after the
previous performance test. If you elect to
[[Page 7166]]
demonstrate compliance using emission averaging under Sec. 63.7522,
you must continue to conduct performance tests annually. The
requirement to test at maximum chloride input level is waived unless
the stack test is conducted for HCl. The requirement to test at maximum
mercury input level is waived unless the stack test is conducted for
mercury. The requirement to test at maximum TSM input level is waived
unless the stack test is conducted for TSM.
(c) If a performance test shows emissions exceeded the emission
limit or 75 percent of the emission limit (as specified in Tables 1 and
2 or 11 through 13 to this subpart) for a pollutant, you must conduct
annual performance tests for that pollutant until all performance tests
over a consecutive 2-year period meet the required level (at or below
75 percent of the emission limit, as specified in Tables 1 and 2 or 11
through 13 to this subpart).
(d) If you are required to meet an applicable tune-up work practice
standard, you must conduct an annual, biennial, or 5-year performance
tune-up according to Sec. 63.7540(a)(10), (11), or (12), respectively.
Each annual tune-up specified in Sec. 63.7540(a)(10) must be no more
than 13 months after the previous tune-up. Each biennial tune-up
specified in Sec. 63.7540(a)(11) must be conducted no more than 25
months after the previous tune-up. Each 5-year tune-up specified in
Sec. 63.7540(a)(12) must be conducted no more than 61 months after the
previous tune-up. For a new or reconstructed affected source (as
defined in Sec. 63.7490), the first annual, biennial, or 5-year tune-
up must be no later than 13 months, 25 months, or 61 months,
respectively, after the initial startup of the new or reconstructed
affected source.
(e) If you demonstrate compliance with the mercury, HCl, or TSM
based on fuel analysis, you must conduct a monthly fuel analysis
according to Sec. 63.7521 for each type of fuel burned that is subject
to an emission limit in Tables 1, 2, or 11 through 13 to this subpart.
You may comply with this monthly requirement by completing the fuel
analysis any time within the calendar month as long as the analysis is
separated from the previous analysis by at least 14 calendar days. If
you burn a new type of fuel, you must conduct a fuel analysis before
burning the new type of fuel in your boiler or process heater. You must
still meet all applicable continuous compliance requirements in Sec.
63.7540. If each of 12 consecutive monthly fuel analyses demonstrates
75 percent or less of the compliance level, you may decrease the fuel
analysis frequency to quarterly for that fuel. If any quarterly sample
exceeds 75 percent of the compliance level or you begin burning a new
type of fuel, you must return to monthly monitoring for that fuel,
until 12 months of fuel analyses are again less than 75 percent of the
compliance level.
(f) You must report the results of performance tests and the
associated fuel analyses within 60 days after the completion of the
performance tests. This report must also verify that the operating
limits for each boiler or process heater have not changed or provide
documentation of revised operating limits established according to
Sec. 63.7530 and Table 7 to this subpart, as applicable. The reports
for all subsequent performance tests must include all applicable
information required in Sec. 63.7550.
(g) For affected sources (as defined in Sec. 63.7490) that have
not operated since the previous compliance demonstration and more than
one year has passed since the previous compliance demonstration, you
must complete the subsequent compliance demonstration, if subject to
the emission limits in Tables 1, 2, or 11 through 13 to this subpart,
no later than 180 days after the re-start of the affected source and
according to the applicable provisions in Sec. 63.7(a)(2) as cited in
Table 10 to this subpart. You must complete a subsequent tune-up by
following the procedures described in Sec. 63.7540(a)(10)(i) through
(vi) and the schedule described in Sec. 63.7540(a)(13) for units that
are not operating at the time of their scheduled tune-up.
(h) If your affected boiler or process heater is in the unit
designed to burn light liquid subcategory and you combust ultra low
sulfur liquid fuel, you do not need to conduct further performance
tests if the pollutants measured during the initial compliance
performance tests meet the emission limits in Tables 1 or 2 of this
subpart providing you demonstrate ongoing compliance with the emissions
limits by monitoring and recording the type of fuel combusted on a
monthly basis. If you intend to use a fuel other than ultra low sulfur
liquid fuel, natural gas, refinery gas, or other gas 1 fuel, you must
conduct new performance tests within 60 days of burning the new fuel
type.
(i) If you operate a CO CEMS that meets the Performance
Specifications outlined in Sec. 63.7525(a)(3) of this subpart to
demonstrate compliance with the applicable alternative CO CEMS emission
standard listed in Tables 1, 2, or 11 through 13 to this subpart, you
are not required to conduct CO performance tests and are not subject to
the oxygen concentration operating limit requirement specified in Sec.
63.7510(a).
0
14. Section Sec. 63.7520 is amended by revising paragraphs (a), (c),
(d), and (e) and adding paragraph (f) to read as follows:
Sec. 63.7520 What stack tests and procedures must I use?
(a) You must conduct all performance tests according to Sec.
63.7(c), (d), (f), and (h). You must also develop a site-specific stack
test plan according to the requirements in Sec. 63.7(c). You shall
conduct all performance tests under such conditions as the
Administrator specifies to you based on the representative performance
of each boiler or process heater for the period being tested. Upon
request, you shall make available to the Administrator such records as
may be necessary to determine the conditions of the performance tests.
* * * * *
(c) You must conduct each performance test under the specific
conditions listed in Tables 5 and 7 to this subpart. You must conduct
performance tests at representative operating load conditions while
burning the type of fuel or mixture of fuels that has the highest
content of chlorine and mercury, and TSM if you are opting to comply
with the TSM alternative standard and you must demonstrate initial
compliance and establish your operating limits based on these
performance tests. These requirements could result in the need to
conduct more than one performance test. Following each performance test
and until the next performance test, you must comply with the operating
limit for operating load conditions specified in Table 4 to this
subpart.
(d) You must conduct a minimum of three separate test runs for each
performance test required in this section, as specified in Sec.
63.7(e)(3). Each test run must comply with the minimum applicable
sampling times or volumes specified in Tables 1 and 2 or 11 through 13
to this subpart.
(e) To determine compliance with the emission limits, you must use
the F-Factor methodology and equations in sections 12.2 and 12.3 of EPA
Method 19 at 40 CFR part 60, appendix A-7 of this chapter to convert
the measured particulate matter (PM) concentrations, the measured HCl
concentrations, the measured mercury concentrations, and the measured
TSM concentrations that result from the performance test to pounds per
million Btu heat input emission rates.
[[Page 7167]]
(f) Except for a 30-day rolling average based on CEMS (or sorbent
trap monitoring system) data, if measurement results for any pollutant
are reported as below the method detection level (e.g., laboratory
analytical results for one or more sample components are below the
method defined analytical detection level), you must use the method
detection level as the measured emissions level for that pollutant in
calculating compliance. The measured result for a multiple component
analysis (e.g., analytical values for multiple Method 29 fractions both
for individual HAP metals and for total HAP metals) may include a
combination of method detection level data and analytical data reported
above the method detection level.
0
15. Section 63.7521 is revised to read as follows:
Sec. 63.7521 What fuel analyses, fuel specification, and procedures
must I use?
(a) For solid and liquid fuels, you must conduct fuel analyses for
chloride and mercury according to the procedures in paragraphs (b)
through (e) of this section and Table 6 to this subpart, as applicable.
For solid fuels and liquid fuels, you must also conduct fuel analyses
for TSM if you are opting to comply with the TSM alternative standard.
For gas 2 (other) fuels, you must conduct fuel analyses for mercury
according to the procedures in paragraphs (b) through (e) of this
section and Table 6 to this subpart, as applicable. (For gaseous fuels,
you may not use fuel analyses to comply with the TSM alternative
standard or the HCl standard.) For purposes of complying with this
section, a fuel gas system that consists of multiple gaseous fuels
collected and mixed with each other is considered a single fuel type
and sampling and analysis is only required on the combined fuel gas
system that will feed the boiler or process heater. Sampling and
analysis of the individual gaseous streams prior to combining is not
required. You are not required to conduct fuel analyses for fuels used
for only startup, unit shutdown, and transient flame stability
purposes. You are required to conduct fuel analyses only for fuels and
units that are subject to emission limits for mercury, HCl, or TSM in
Tables 1 and 2 or 11 through 13 to this subpart. Gaseous and liquid
fuels are exempt from the sampling requirements in paragraphs (c) and
(d) of this section and Table 6 to this subpart.
(b) You must develop a site-specific fuel monitoring plan according
to the following procedures and requirements in paragraphs (b)(1) and
(2) of this section, if you are required to conduct fuel analyses as
specified in Sec. 63.7510.
(1) If you intend to use an alternative analytical method other
than those required by Table 6 to this subpart, you must submit the
fuel analysis plan to the Administrator for review and approval no
later than 60 days before the date that you intend to conduct the
initial compliance demonstration described in Sec. 63.7510.
(2) You must include the information contained in paragraphs
(b)(2)(i) through (vi) of this section in your fuel analysis plan.
(i) The identification of all fuel types anticipated to be burned
in each boiler or process heater.
(ii) For each anticipated fuel type, the notification of whether
you or a fuel supplier will be conducting the fuel analysis.
(iii) For each anticipated fuel type, a detailed description of the
sample location and specific procedures to be used for collecting and
preparing the composite samples if your procedures are different from
paragraph (c) or (d) of this section. Samples should be collected at a
location that most accurately represents the fuel type, where possible,
at a point prior to mixing with other dissimilar fuel types.
(iv) For each anticipated fuel type, the analytical methods from
Table 6, with the expected minimum detection levels, to be used for the
measurement of chlorine or mercury.
(v) If you request to use an alternative analytical method other
than those required by Table 6 to this subpart, you must also include a
detailed description of the methods and procedures that you are
proposing to use. Methods in Table 6 shall be used until the requested
alternative is approved.
(vi) If you will be using fuel analysis from a fuel supplier in
lieu of site-specific sampling and analysis, the fuel supplier must use
the analytical methods required by Table 6 to this subpart.
(c) At a minimum, you must obtain three composite fuel samples for
each fuel type according to the procedures in paragraph (c)(1) or (2)
of this section, or the methods listed in Table 6 to this subpart, or
use an automated sampling mechanism that provides representative
composite fuel samples for each fuel type that includes both coarse and
fine material.
(1) If sampling from a belt (or screw) feeder, collect fuel samples
according to paragraphs (c)(1)(i) and (ii) of this section.
(i) Stop the belt and withdraw a 6-inch wide sample from the full
cross-section of the stopped belt to obtain a minimum two pounds of
sample. You must collect all the material (fines and coarse) in the
full cross-section. You must transfer the sample to a clean plastic
bag.
(ii) Each composite sample will consist of a minimum of three
samples collected at approximately equal one-hour intervals during the
testing period for sampling during performance stack testing. For
monthly sampling, each composite sample shall be collected at
approximately equal 10-day intervals during the month.
(2) If sampling from a fuel pile or truck, you must collect fuel
samples according to paragraphs (c)(2)(i) through (iii) of this
section.
(i) For each composite sample, you must select a minimum of five
sampling locations uniformly spaced over the surface of the pile.
(ii) At each sampling site, you must dig into the pile to a uniform
depth of approximately 18 inches. You must insert a clean shovel into
the hole and withdraw a sample, making sure that large pieces do not
fall off during sampling; use the same shovel to collect all samples.
(iii) You must transfer all samples to a clean plastic bag for
further processing.
(d) You must prepare each composite sample according to the
procedures in paragraphs (d)(1) through (7) of this section.
(1) You must thoroughly mix and pour the entire composite sample
over a clean plastic sheet.
(2) You must break large sample pieces (e.g., larger than 3 inches)
into smaller sizes.
(3) You must make a pie shape with the entire composite sample and
subdivide it into four equal parts.
(4) You must separate one of the quarter samples as the first
subset.
(5) If this subset is too large for grinding, you must repeat the
procedure in paragraph (d)(3) of this section with the quarter sample
and obtain a one-quarter subset from this sample.
(6) You must grind the sample in a mill.
(7) You must use the procedure in paragraph (d)(3) of this section
to obtain a one-quarter subsample for analysis. If the quarter sample
is too large, subdivide it further using the same procedure.
(e) You must determine the concentration of pollutants in the fuel
(mercury and/or chlorine and/or TSM) in units of pounds per million Btu
of each composite sample for each fuel type according to the procedures
in
[[Page 7168]]
Table 6 to this subpart, for use in Equations 7, 8, and 9 of this
subpart.
(f) To demonstrate that a gaseous fuel other than natural gas or
refinery gas qualifies as an other gas 1 fuel, as defined in Sec.
63.7575, you must conduct a fuel specification analyses for mercury
according to the procedures in paragraphs (g) through (i) of this
section and Table 6 to this subpart, as applicable, except as specified
in paragraph (f)(1) through (4) of this section.
(1) You are not required to conduct the fuel specification analyses
in paragraphs (g) through (i) of this section for natural gas or
refinery gas.
(2) You are not required to conduct the fuel specification analyses
in paragraphs (g) through (i) of this section for gaseous fuels that
are subject to another subpart of this part, part 60, part 61, or part
65.
(3) You are not required to conduct the fuel specification analyses
in paragraphs (g) through (i) of this section on gaseous fuels for
units that are complying with the limits for units designed to burn gas
2 (other) fuels.
(4) You are not required to conduct the fuel specification analyses
in paragraphs (g) through (i) of this section for gas streams directly
derived from natural gas at natural gas production sites or natural gas
plants.
(g) You must develop and submit a site-specific fuel analysis plan
for other gas 1 fuels to the EPA Administrator for review and approval
according to the following procedures and requirements in paragraphs
(g)(1) and (2) of this section.
(1) If you intend to use an alternative analytical method other
than those required by Table 6 to this subpart, you must submit the
fuel analysis plan to the Administrator for review and approval no
later than 60 days before the date that you intend to conduct the
initial compliance demonstration described in Sec. 63.7510.
(2) You must include the information contained in paragraphs
(g)(2)(i) through (vi) of this section in your fuel analysis plan.
(i) The identification of all gaseous fuel types other than those
exempted from fuel specification analysis under (f)(1) through (3) of
this section anticipated to be burned in each boiler or process heater.
(ii) For each anticipated fuel type, the notification of whether
you or a fuel supplier will be conducting the fuel specification
analysis.
(iii) For each anticipated fuel type, a detailed description of the
sample location and specific procedures to be used for collecting and
preparing the samples if your procedures are different from the
sampling methods contained in Table 6 to this subpart. Samples should
be collected at a location that most accurately represents the fuel
type, where possible, at a point prior to mixing with other dissimilar
fuel types. If multiple boilers or process heaters are fueled by a
common fuel stream it is permissible to conduct a single gas
specification at the common point of gas distribution.
(iv) For each anticipated fuel type, the analytical methods from
Table 6 to this subpart, with the expected minimum detection levels, to
be used for the measurement of mercury.
(v) If you request to use an alternative analytical method other
than those required by Table 6 to this subpart, you must also include a
detailed description of the methods and procedures that you are
proposing to use. Methods in Table 6 to this subpart shall be used
until the requested alternative is approved.
(vi) If you will be using fuel analysis from a fuel supplier in
lieu of site-specific sampling and analysis, the fuel supplier must use
the analytical methods required by Table 6 to this subpart.
(h) You must obtain a single fuel sample for each fuel type
according to the sampling procedures listed in Table 6 for fuel
specification of gaseous fuels.
(i) You must determine the concentration in the fuel of mercury, in
units of microgram per cubic meter, dry basis, of each sample for each
other gas 1 fuel type according to the procedures in Table 6 to this
subpart.
0
16. Section Sec. 63.7522 is revised by:
0
a. Revising paragraphs (a) through (d).
0
b. Revising paragraphs (e)(1) and (2).
0
c. Revising paragraphs (f) introductory text and (f)(1) and (2).
0
d. Revising paragraphs (g) introductory text, (g)(2)(i), (g)(2)(iv),
(g)(2)(vi)(B), (g)(3) introductory text, (g)(4) introductory text, and
(g)(4)(ii).
0
e. Revising paragraph (h).
0
f. Revising paragraph (i).
0
g. Revising paragraph (j)(1).
0
h. Revising paragraph (k).
The revisions read as follows:
Sec. 63.7522 Can I use emissions averaging to comply with this
subpart?
(a) As an alternative to meeting the requirements of Sec. 63.7500
for PM (or TSM), HCl, or mercury on a boiler or process heater-specific
basis, if you have more than one existing boiler or process heater in
any subcategories located at your facility, you may demonstrate
compliance by emissions averaging, if your averaged emissions are not
more than 90 percent of the applicable emission limit, according to the
procedures in this section. You may not include new boilers or process
heaters in an emissions average.
(b) For a group of two or more existing boilers or process heaters
in the same subcategory that each vent to a separate stack, you may
average PM (or TSM), HCl, or mercury emissions among existing units to
demonstrate compliance with the limits in Table 2 to this subpart as
specified in paragraph (b)(1) through (3) of this section, if you
satisfy the requirements in paragraphs (c) through (g) of this section.
(1) You may average units using a CEMS or PM CPMS for demonstrating
compliance.
(2) For mercury and HCl, averaging is allowed as follows:
(i) You may average among units in any of the solid fuel
subcategories.
(ii) You may average among units in any of the liquid fuel
subcategories.
(iii) You may average among units in a subcategory of units
designed to burn gas 2 (other) fuels.
(iv) You may not average across the units designed to burn liquid,
units designed to burn solid fuel, and units designed to burn gas 2
(other) subcategories.
(3) For PM (or TSM), averaging is only allowed between units within
each of the following subcategories and you may not average across
subcategories:
(i) Units designed to burn coal/solid fossil fuel.
(ii) Stokers/sloped grate/other units designed to burn kiln dried
biomass/bio-based solids.
(iii) Stokers/sloped grate/other units designed to burn wet
biomass/bio-based solids.
(iv) Fluidized bed units designed to burn biomass/bio-based solid.
(v) Suspension burners designed to burn biomass/bio-based solid.
(vi) Dutch ovens/pile burners designed to burn biomass/bio-based
solid.
(vii) Fuel Cells designed to burn biomass/bio-based solid.
(viii) Hybrid suspension/grate burners designed to burn wet
biomass/bio-based solid.
(ix) Units designed to burn heavy liquid fuel.
(x) Units designed to burn light liquid fuel.
(xi) Units designed to burn liquid fuel that are non-continental
units.
(xii) Units designed to burn gas 2 (other) gases.
(c) For each existing boiler or process heater in the averaging
group, the emission rate achieved during the initial compliance test
for the HAP being averaged must not exceed the emission level that was
being achieved on
[[Page 7169]]
January 31, 2013 or the control technology employed during the initial
compliance test must not be less effective for the HAP being averaged
than the control technology employed on January 31, 2013.
(d) The averaged emissions rate from the existing boilers and
process heaters participating in the emissions averaging option must
not exceed 90 percent of the limits in Table 2 to this subpart at all
times the affected units are operating following the compliance date
specified in Sec. 63.7495.
(e) * * *
(1) You must use Equation 1a or 1b or 1c of this section to
demonstrate that the PM (or TSM), HCl, or mercury emissions from all
existing units participating in the emissions averaging option for that
pollutant do not exceed the emission limits in Table 2 to this subpart.
Use Equation 1a if you are complying with the emission limits on a heat
input basis, use Equation 1b if you are complying with the emission
limits on a steam generation (output) basis, and use Equation 1c if you
are complying with the emission limits on a electric generation
(output) basis.
[GRAPHIC] [TIFF OMITTED] TR31JA13.004
Where:
AveWeightedEmissions = Average weighted emissions for PM (or TSM),
HCl, or mercury, in units of pounds per million Btu of heat input.
Er = Emission rate (as determined during the initial compliance
demonstration) of PM (or TSM), HCl, or mercury from unit, i, in
units of pounds per million Btu of heat input. Determine the
emission rate for PM (or TSM), HCl, or mercury by performance
testing according to Table 5 to this subpart, or by fuel analysis
for HCl or mercury or TSM using the applicable equation in Sec.
63.7530(c).
Hm = Maximum rated heat input capacity of unit, i, in units of
million Btu per hour.
n = Number of units participating in the emissions averaging option.
1.1 = Required discount factor.
[GRAPHIC] [TIFF OMITTED] TR31JA13.005
Where:
AveWeightedEmissions = Average weighted emissions for PM (or TSM),
HCl, or mercury, in units of pounds per million Btu of steam output.
Er = Emission rate (as determined during the initial compliance
demonstration) of PM (or TSM), HCl, or mercury from unit, i, in
units of pounds per million Btu of steam output. Determine the
emission rate for PM (or TSM), HCl, or mercury by performance
testing according to Table 5 to this subpart, or by fuel analysis
for HCl or mercury or TSM using the applicable equation in Sec.
63.7530(c). If you are taking credit for energy conservation
measures from a unit according to Sec. 63.7533, use the adjusted
emission level for that unit, Eadj, determined according to Sec.
63.7533 for that unit.
So = Maximum steam output capacity of unit, i, in units of million
Btu per hour, as defined in Sec. 63.7575.
n = Number of units participating in the emissions averaging option.
1.1 = Required discount factor.
[GRAPHIC] [TIFF OMITTED] TR31JA13.006
Where:
AveWeightedEmissions = Average weighted emissions for PM (or TSM),
HCl, or mercury, in units of pounds per megawatt hour.
Er = Emission rate (as determined during the initial compliance
demonstration) of PM (or TSM), HCl, or mercury from unit, i, in
units of pounds per megawatt hour. Determine the emission rate for
PM (or TSM), HCl, or mercury by performance testing according to
Table 5 to this subpart, or by fuel analysis for HCl or mercury or
TSM using the applicable equation in Sec. 63.7530(c). If you are
taking credit for energy conservation measures from a unit according
to Sec. 63.7533, use the adjusted emission level for that unit,
Eadj, determined according to Sec. 63.7533 for that unit.
Eo = Maximum electric generating output capacity of unit, i, in
units of megawatt hour, as defined in Sec. 63.7575.
n = Number of units participating in the emissions averaging option.
1.1 = Required discount factor.
(2) If you are not capable of determining the maximum rated heat
input capacity of one or more boilers that generate steam, you may use
Equation 2 of this section as an alternative to using Equation 1a of
this section to demonstrate that the PM (or TSM), HCl, or mercury
emissions from all existing units participating in the emissions
averaging option do not exceed the emission limits for that pollutant
in Table 2 to this subpart that are in pounds per million Btu of heat
input.
[GRAPHIC] [TIFF OMITTED] TR31JA13.007
Where:
AveWeightedEmissions = Average weighted emission level for PM (or
TSM), HCl, or mercury, in units of pounds per million Btu of heat
input.
Er = Emission rate (as determined during the most recent compliance
demonstration) of PM (or TSM), HCl, or mercury from unit, i, in
units of pounds per million Btu of heat input. Determine the
emission rate for PM (or TSM), HCl, or mercury by performance
testing according to Table 5 to this subpart, or by fuel analysis
for HCl or mercury or TSM using the applicable equation in Sec.
63.7530(c).
[[Page 7170]]
Sm = Maximum steam generation capacity by unit, i, in units of
pounds per hour.
Cfi = Conversion factor, calculated from the most recent compliance
test, in units of million Btu of heat input per pounds of steam
generated for unit, i.
1.1 = Required discount factor.
(f) After the initial compliance demonstration described in
paragraph (e) of this section, you must demonstrate compliance on a
monthly basis determined at the end of every month (12 times per year)
according to paragraphs (f)(1) through (3) of this section. The first
monthly period begins on the compliance date specified in Sec.
63.7495. If the affected source elects to collect monthly data for up
the 11 months preceding the first monthly period, these additional data
points can be used to compute the 12-month rolling average in paragraph
(f)(3) of this section.
(1) For each calendar month, you must use Equation 3a or 3b or 3c
of this section to calculate the average weighted emission rate for
that month. Use Equation 3a and the actual heat input for the month for
each existing unit participating in the emissions averaging option if
you are complying with emission limits on a heat input basis. Use
Equation 3b and the actual steam generation for the month if you are
complying with the emission limits on a steam generation (output)
basis. Use Equation 3c and the actual steam generation for the month if
you are complying with the emission limits on a electrical generation
(output) basis.
[GRAPHIC] [TIFF OMITTED] TR31JA13.008
Where:
AveWeightedEmissions = Average weighted emission level for PM (or
TSM), HCl, or mercury, in units of pounds per million Btu of heat
input, for that calendar month.
Er = Emission rate (as determined during the most recent compliance
demonstration) of PM (or TSM), HCl, or mercury from unit, i, in
units of pounds per million Btu of heat input. Determine the
emission rate for PM (or TSM), HCl, or mercury by performance
testing according to Table 5 to this subpart, or by fuel analysis
for HCl or mercury or TSM according to Table 6 to this subpart.
Hb = The heat input for that calendar month to unit, i, in units of
million Btu.
n = Number of units participating in the emissions averaging option.
1.1 = Required discount factor.
[GRAPHIC] [TIFF OMITTED] TR31JA13.009
Where:
AveWeightedEmissions = Average weighted emission level for PM (or
TSM), HCl, or mercury, in units of pounds per million Btu of steam
output, for that calendar month.
Er = Emission rate (as determined during the most recent compliance
demonstration) of PM (or TSM), HCl, or mercury from unit, i, in
units of pounds per million Btu of steam output. Determine the
emission rate for PM (or TSM), HCl, or mercury by performance
testing according to Table 5 to this subpart, or by fuel analysis
for HCl or mercury or TSM according to Table 6 to this subpart. If
you are taking credit for energy conservation measures from a unit
according to Sec. 63.7533, use the adjusted emission level for that
unit, Eadj, determined according to Sec. 63.7533 for
that unit.
So = The steam output for that calendar month from unit, i, in units
of million Btu, as defined in Sec. 63.7575.
n = Number of units participating in the emissions averaging option.
1.1 = Required discount factor.
[GRAPHIC] [TIFF OMITTED] TR31JA13.010
Where:
AveWeightedEmissions = Average weighted emission level for PM (or
TSM), HCl, or mercury, in units of pounds per megawatt hour, for
that calendar month.
Er = Emission rate (as determined during the most recent compliance
demonstration) of PM (or TSM), HCl, or mercury from unit, i, in
units of pounds per megawatt hour. Determine the emission rate for
PM (or TSM), HCl, or mercury by performance testing according to
Table 5 to this subpart, or by fuel analysis for HCl or mercury or
TSM according to Table 6 to this subpart. If you are taking credit
for energy conservation measures from a unit according to Sec.
63.7533, use the adjusted emission level for that unit,
Eadj, determined according to Sec. 63.7533 for that
unit.
Eo = The electric generating output for that calendar month from
unit, i, in units of megawatt hour, as defined in Sec. 63.7575.
n = Number of units participating in the emissions averaging option.
1.1 = Required discount factor.
(2) If you are not capable of monitoring heat input, you may use
Equation 4 of this section as an alternative to using Equation 3a of
this section to calculate the average weighted emission rate using the
actual steam generation from the boilers participating in the emissions
averaging option.
[GRAPHIC] [TIFF OMITTED] TR31JA13.011
Where:
AveWeightedEmissions = average weighted emission level for PM (or
TSM), HCl, or mercury, in units of pounds per million
[[Page 7171]]
Btu of heat input for that calendar month.
Er = Emission rate (as determined during the most recent compliance
demonstration of PM (or TSM), HCl, or mercury from unit, i, in units
of pounds per million Btu of heat input. Determine the emission rate
for PM (or TSM), HCl, or mercury by performance testing according to
Table 5 to this subpart, or by fuel analysis for HCl or mercury or
TSM according to Table 6 to this subpart.
Sa = Actual steam generation for that calendar month by boiler, i,
in units of pounds.
Cfi = Conversion factor, as calculated during the most recent
compliance test, in units of million Btu of heat input per pounds of
steam generated for boiler, i.
1.1 = Required discount factor.
* * * * *
(g) You must develop, and submit upon request to the applicable
Administrator for review and approval, an implementation plan for
emission averaging according to the following procedures and
requirements in paragraphs (g)(1) through (4) of this section.
* * * * *
(2) * * *
(i) The identification of all existing boilers and process heaters
in the averaging group, including for each either the applicable HAP
emission level or the control technology installed as of January 31,
2013 and the date on which you are requesting emission averaging to
commence;
* * * * *
(iv) The test plan for the measurement of PM (or TSM), HCl, or
mercury emissions in accordance with the requirements in Sec. 63.7520;
* * * * *
(vi) * * *
(B) A description of the methods and procedures that will be used
to demonstrate that the parameter indicates proper operation of the
control device; the frequency and content of monitoring, reporting, and
recordkeeping requirements; and a demonstration, to the satisfaction of
the Administrator, that the proposed monitoring frequency is sufficient
to represent control device operating conditions; and
* * * * *
(3) The Administrator shall review and approve or disapprove the
plan according to the following criteria:
* * * * *
(4) The applicable Administrator shall not approve an emission
averaging implementation plan containing any of the following
provisions:
* * * * *
(ii) The inclusion of any emission source other than an existing
unit in the same subcategories.
* * * * *
(h) For a group of two or more existing affected units, each of
which vents through a single common stack, you may average PM (or TSM),
HCl, or mercury emissions to demonstrate compliance with the limits for
that pollutant in Table 2 to this subpart if you satisfy the
requirements in paragraph (i) or (j) of this section.
(i) For a group of two or more existing units in the same
subcategories, each of which vents through a common emissions control
system to a common stack, that does not receive emissions from units in
other subcategories or categories, you may treat such averaging group
as a single existing unit for purposes of this subpart and comply with
the requirements of this subpart as if the group were a single unit.
(j) * * *
(1) Conduct performance tests according to procedures specified in
Sec. 63.7520 in the common stack if affected units from other
subcategories vent to the common stack. The emission limits that the
group must comply with are determined by the use of Equation 6 of this
section.
[GRAPHIC] [TIFF OMITTED] TR31JA13.012
Where:
En = HAP emission limit, pounds per million British thermal units
(lb/MMBtu), parts per million (ppm), or nanograms per dry standard
cubic meter (ng/dscm).
ELi = Appropriate emission limit from Table 2 to this subpart for
unit i, in units of lb/MMBtu, ppm or ng/dscm.
Hi = Heat input from unit i, MMBtu.
* * * * *
(k) The common stack of a group of two or more existing boilers or
process heaters in the same subcategories subject to paragraph (h) of
this section may be treated as a separate stack for purposes of
paragraph (b) of this section and included in an emissions averaging
group subject to paragraph (b) of this section.
0
17. Section 63.7525 is amended by:
0
a. Revising paragraph (a)
0
b. Revising paragraph (b).
0
c. Revising paragraph (c) introductory text.
0
d. Revising paragraphs (d) introductory text and paragraphs (d)(1)
through (d)(4).
0
e. Revising paragraph (e)(2).
0
f. Revising paragraph (e)(3).
0
g. Revising paragraph (f)(2).
0
h. Revising paragraph (j).
0
i. Revising paragraph (k).
0
j. Adding paragraph (l).
0
k. Adding paragraph (m).
The revisions and additions read as follows:
Sec. 63.7525 What are my monitoring, installation, operation, and
maintenance requirements?
(a) If your boiler or process heater is subject to a CO emission
limit in Tables 1, 2, or 11 through 13 to this subpart, you must
install, operate, and maintain an oxygen analyzer system, as defined in
Sec. 63.7575, or install, certify, operate and maintain continuous
emission monitoring systems for CO and oxygen according to the
procedures in paragraphs (a)(1) through (7) of this section.
(1) Install the CO CEMS and oxygen analyzer by the compliance date
specified in Sec. 63.7495. The CO and oxygen levels shall be monitored
at the same location at the outlet of the boiler or process heater.
(2) To demonstrate compliance with the applicable alternative CO
CEMS emission standard listed in Tables 1, 2, or 11 through 13 to this
subpart, you must install, certify, operate, and maintain a CO CEMS and
an oxygen analyzer according to the applicable procedures under
Performance Specification 4, 4A, or 4B at 40 CFR part 60, appendix B,
the site-specific monitoring plan developed according to Sec.
63.7505(d), and the requirements in Sec. 63.7540(a)(8) and paragraph
(a) of this section. Any boiler or process heater that has a CO CEMS
that is compliant with Performance Specification 4, 4A, or 4B at 40 CFR
part 60, appendix B, a site-specific monitoring plan developed
according to Sec. 63.7505(d), and the requirements in Sec.
63.7540(a)(8) and paragraph (a) of this section must use the CO CEMS to
comply with the applicable alternative CO CEMS emission standard listed
in Tables 1, 2, or 11 through 13 to this subpart.
(i) You must conduct a performance evaluation of each CO CEMS
according to the requirements in Sec. 63.8(e) and
[[Page 7172]]
according to Performance Specification 4, 4A, or 4B at 40 CFR part 60,
appendix B.
(ii) During each relative accuracy test run of the CO CEMS, you
must be collect emission data for CO concurrently (or within a 30- to
60-minute period) by both the CO CEMS and by Method 10, 10A, or 10B at
40 CFR part 60, appendix A-4. The relative accuracy testing must be at
representative operating conditions.
(iii) You must follow the quality assurance procedures (e.g.,
quarterly accuracy determinations and daily calibration drift tests) of
Procedure 1 of appendix F to part 60. The measurement span value of the
CO CEMS must be two times the applicable CO emission limit, expressed
as a concentration.
(iv) Any CO CEMS that does not comply with Sec. 63.7525(a) cannot
be used to meet any requirement in this subpart to demonstrate
compliance with a CO emission limit listed in Tables 1, 2, or 11
through 13 to this subpart.
(v) For a new unit, complete the initial performance evaluation no
later than July 30, 2013, or 180 days after the date of initial
startup, whichever is later. For an existing unit, complete the initial
performance evaluation no later than July 29, 2016.
(3) Complete a minimum of one cycle of CO and oxygen CEMS operation
(sampling, analyzing, and data recording) for each successive 15-minute
period. Collect CO and oxygen data concurrently. Collect at least four
CO and oxygen CEMS data values representing the four 15-minute periods
in an hour, or at least two 15-minute data values during an hour when
CEMS calibration, quality assurance, or maintenance activities are
being performed.
(4) Reduce the CO CEMS data as specified in Sec. 63.8(g)(2).
(5) Calculate one-hour arithmetic averages, corrected to 3 percent
oxygen from each hour of CO CEMS data in parts per million CO
concentration. The one-hour arithmetic averages required shall be used
to calculate the 30-day or 10-day rolling average emissions. Use
Equation 19-19 in section 12.4.1 of Method 19 of 40 CFR part 60,
appendix A-7 for calculating the average CO concentration from the
hourly values.
(6) For purposes of collecting CO data, operate the CO CEMS as
specified in Sec. 63.7535(b). You must use all the data collected
during all periods in calculating data averages and assessing
compliance, except that you must exclude certain data as specified in
Sec. 63.7535(c). Periods when CO data are unavailable may constitute
monitoring deviations as specified in Sec. 63.7535(d).
(7) Operate an oxygen trim system with the oxygen level set no
lower than the lowest hourly average oxygen concentration measured
during the most recent CO performance test as the operating limit for
oxygen according to Table 7 to this subpart.
(b) If your boiler or process heater is in the unit designed to
burn coal/solid fossil fuel subcategory or the unit designed to burn
heavy liquid subcategory and has an average annual heat input rate
greater than 250 MMBtu per hour from solid fossil fuel and/or heavy
liquid, and you demonstrate compliance with the PM limit instead of the
alternative TSM limit, you must install, certify, maintain, and operate
a PM CPMS monitoring emissions discharged to the atmosphere and record
the output of the system as specified in paragraphs (b)(1) through (4)
of this section. As an alternative to use of a PM CPMS to demonstrate
compliance with the PM limit, you may choose to use a PM CEMS. If you
choose to use a PM CEMS to demonstrate compliance with the PM limit
instead of the alternative TSM limit, you must install, certify,
maintain, and operate a PM CEMS monitoring emissions discharged to the
atmosphere and record the output of the system as specified in
paragraph (b)(5) through (8) of this section. For other boilers or
process heaters, you may elect to use a PM CPMS or PM CEMS operated in
accordance with this section in lieu of using other CMS for monitoring
PM compliance (e.g., bag leak detectors, ESP secondary power, PM
scrubber pressure). Owners of boilers and process heaters who elect to
comply with the alternative TSM limit are not required to install a PM
CPMS.
(1) Install, certify, operate, and maintain your PM CPMS according
to the procedures in your approved site-specific monitoring plan
developed in accordance with Sec. 63.7505(d), the requirements in
Sec. 63.7540(a)(9), and paragraphs (b)(1)(i) through (iii) of this
section.
(i) The operating principle of the PM CPMS must be based on in-
stack or extractive light scatter, light scintillation, beta
attenuation, or mass accumulation detection of PM in the exhaust gas or
representative exhaust gas sample. The reportable measurement output
from the PM CPMS must be expressed as milliamps.
(ii) The PM CPMS must have a cycle time (i.e., period required to
complete sampling, measurement, and reporting for each measurement) no
longer than 60 minutes.
(iii) The PM CPMS must be capable of detecting and responding to PM
concentrations of no greater than 0.5 milligram per actual cubic meter.
(2) For a new unit, complete the initial performance evaluation no
later than July 30, 2013, or 180 days after the date of initial
startup, whichever is later. For an existing unit, complete the initial
performance evaluation no later than July 29, 2016.
(3) Collect PM CPMS hourly average output data for all boiler or
process heater operating hours except as indicated in Sec. 63.7535(a)
through (d). Express the PM CPMS output as milliamps.
(4) Calculate the arithmetic 30-day rolling average of all of the
hourly average PM CPMS output data collected during all boiler or
process heater operating hours (milliamps).
(5) Install, certify, operate, and maintain your PM CEMS according
to the procedures in your approved site-specific monitoring plan
developed in accordance with Sec. 63.7505(d), the requirements in
Sec. 63.7540(a)(9), and paragraphs (b)(5)(i) through (iv) of this
section.
(i) You shall conduct a performance evaluation of the PM CEMS
according to the applicable requirements of Sec. 60.8(e), and
Performance Specification 11 at 40 CFR part 60, appendix B of this
chapter.
(ii) During each PM correlation testing run of the CEMS required by
Performance Specification 11 at 40 CFR part 60, appendix B of this
chapter, you shall collect PM and oxygen (or carbon dioxide) data
concurrently (or within a 30-to 60-minute period) by both the CEMS and
conducting performance tests using Method 5 at 40 CFR part 60, appendix
A-3 or Method 17 at 40 CFR part 60, appendix A-6 of this chapter.
(iii) You shall perform quarterly accuracy determinations and daily
calibration drift tests in accordance with Procedure 2 at 40 CFR part
60, appendix F of this chapter. You must perform Relative Response
Audits annually and perform Response Correlation Audits every 3 years.
(iv) Within 60 days after the date of completing each CEMS relative
accuracy test audit or performance test conducted to demonstrate
compliance with this subpart, you must submit the relative accuracy
test audit data and performance test data to the EPA by successfully
submitting the data electronically into the EPA's Central Data Exchange
by using the Electronic Reporting Tool (see https://www.epa.gov/ttn/chief/ert/erttool.html/).
(6) For a new unit, complete the initial performance evaluation no
later than July 30, 2013, or 180 days after the date of initial
startup, whichever is later. For an existing unit, complete the
[[Page 7173]]
initial performance evaluation no later than July 29, 2016.
(7) Collect PM CEMS hourly average output data for all boiler or
process heater operating hours except as indicated in Sec. 63.7535(a)
through (d).
(8) Calculate the arithmetic 30-day rolling average of all of the
hourly average PM CEMS output data collected during all boiler or
process heater operating hours.
(c) If you have an applicable opacity operating limit in this rule,
and are not otherwise required or elect to install and operate a PM
CPMS, PM CEMS, or a bag leak detection system, you must install,
operate, certify and maintain each COMS according to the procedures in
paragraphs (c)(1) through (7) of this section by the compliance date
specified in Sec. 63.7495.
* * * * *
(d) If you have an operating limit that requires the use of a CMS
other than a PM CPMS or COMS, you must install, operate, and maintain
each CMS according to the procedures in paragraphs (d)(1) through (5)
of this section by the compliance date specified in Sec. 63.7495.
(1) The CPMS must complete a minimum of one cycle of operation
every 15-minutes. You must have a minimum of four successive cycles of
operation, one representing each of the four 15-minute periods in an
hour, to have a valid hour of data.
(2) You must operate the monitoring system as specified in Sec.
63.7535(b), and comply with the data calculation requirements specified
in Sec. 63.7535(c).
(3) Any 15-minute period for which the monitoring system is out-of-
control and data are not available for a required calculation
constitutes a deviation from the monitoring requirements. Other
situations that constitute a monitoring deviation are specified in
Sec. 63.7535(d).
(4) You must determine the 30-day rolling average of all recorded
readings, except as provided in Sec. 63.7535(c).
* * * * *
(e) * * *
(2) You must use a flow sensor with a measurement sensitivity of no
greater than 2 percent of the design flow rate.
(3) You must minimize, consistent with good engineering practices,
the effects of swirling flow or abnormal velocity distributions due to
upstream and downstream disturbances.
* * * * *
(f) * * *
(2) Minimize or eliminate pulsating pressure, vibration, and
internal and external corrosion consistent with good engineering
practices.
* * * * *
(j) If you are not required to use a PM CPMS and elect to use a
fabric filter bag leak detection system to comply with the requirements
of this subpart, you must install, calibrate, maintain, and
continuously operate the bag leak detection system as specified in
paragraphs (j)(1) through (6) of this section.
(1) You must install a bag leak detection sensor(s) in a
position(s) that will be representative of the relative or absolute PM
loadings for each exhaust stack, roof vent, or compartment (e.g., for a
positive pressure fabric filter) of the fabric filter.
(2) Conduct a performance evaluation of the bag leak detection
system in accordance with your monitoring plan and consistent with the
guidance provided in EPA-454/R-98-015 (incorporated by reference, see
Sec. 63.14).
(3) Use a bag leak detection system certified by the manufacturer
to be capable of detecting PM emissions at concentrations of 10
milligrams per actual cubic meter or less.
(4) Use a bag leak detection system equipped with a device to
record continuously the output signal from the sensor.
(5) Use a bag leak detection system equipped with a system that
will alert plant operating personnel when an increase in relative PM
emissions over a preset level is detected. The alert must easily
recognizable (e.g., heard or seen) by plant operating personnel.
(6) Where multiple bag leak detectors are required, the system's
instrumentation and alert may be shared among detectors.
(k) For each unit that meets the definition of limited-use boiler
or process heater, you must keep fuel use records for the days the
boiler or process heater was operating.
(l) For each unit for which you decide to demonstrate compliance
with the mercury or HCl emissions limits in Tables 1 or 2 or 11 through
13 of this subpart by use of a CEMS for mercury or HCl, you must
install, certify, maintain, and operate a CEMS measuring emissions
discharged to the atmosphere and record the output of the system as
specified in paragraphs (l)(1) through (8) of this section. For HCl,
this option for an affected unit takes effect on the date a final
performance specification for a HCl CEMS is published in the Federal
Register or the date of approval of a site-specific monitoring plan.
(1) Notify the Administrator one month before starting use of the
CEMS, and notify the Administrator one month before stopping use of the
CEMS.
(2) Each CEMS shall be installed, certified, operated, and
maintained according to the requirements in Sec. 63.7540(a)(14) for a
mercury CEMS and Sec. 63.7540(a)(15) for a HCl CEMS.
(3) For a new unit, you must complete the initial performance
evaluation of the CEMS by the latest of the dates specified in
paragraph (l)(3)(i) through (iii) of this section.
(i) No later than July 30, 2013.
(ii) No later 180 days after the date of initial startup.
(iii) No later 180 days after notifying the Administrator before
starting to use the CEMS in place of performance testing or fuel
analysis to demonstrate compliance.
(4) For an existing unit, you must complete the initial performance
evaluation by the latter of the two dates specified in paragraph
(l)(4)(i) and (ii) of this section.
(i) No later than July 29, 2016.
(ii) No later 180 days after notifying the Administrator before
starting to use the CEMS in place of performance testing or fuel
analysis to demonstrate compliance.
(5) Compliance with the applicable emissions limit shall be
determined based on the 30-day rolling average of the hourly arithmetic
average emissions rates using the continuous monitoring system outlet
data. The 30-day rolling arithmetic average emission rate (lb/MMBtu)
shall be calculated using the equations in EPA Reference Method 19 at
40 CFR part 60, appendix A-7, but substituting the mercury or HCl
concentration for the pollutant concentrations normally used in Method
19.
(6) Collect CEMS hourly averages for all operating hours on a 30-
day rolling average basis. Collect at least four CMS data values
representing the four 15-minute periods in an hour, or at least two 15-
minute data values during an hour when CMS calibration, quality
assurance, or maintenance activities are being performed.
(7) The one-hour arithmetic averages required shall be expressed in
lb/MMBtu and shall be used to calculate the boiler 30-day and 10-day
rolling average emissions.
(8) You are allowed to substitute the use of the PM, mercury or HCl
CEMS for the applicable fuel analysis, annual performance test, and
operating limits specified in Table 4 to this subpart to demonstrate
compliance with the PM, mercury or HCl emissions limit, and if you are
using an acid gas wet scrubber or dry sorbent injection control
technology to comply with the HCl emission limit, you are allowed to
substitute the use of a sulfur dioxide
[[Page 7174]]
(SO2) CEMS for the applicable fuel analysis, annual
performance test, and operating limits specified in Table 4 to this
subpart to demonstrate compliance with HCl emissions limit.
(m) If your unit is subject to a HCl emission limit in Tables 1, 2,
or 11 through 13 of this subpart and you have an acid gas wet scrubber
or dry sorbent injection control technology and you use an
SO2 CEMS, you must install the monitor at the outlet of the
boiler or process heater, downstream of all emission control devices,
and you must install, certify, operate, and maintain the CEMS according
to part 75 of this chapter.
(1) The SO2 CEMS must be installed by the compliance
date specified in Sec. 63.7495.
(2) For on-going quality assurance (QA), the SO2 CEMS
must meet the applicable daily, quarterly, and semiannual or annual
requirements in sections 2.1 through 2.3 of appendix B to part 75 of
this chapter, with the following addition: You must perform the
linearity checks required in section 2.2 of appendix B to part 75 of
this chapter if the SO2 CEMS has a span value of 30 ppm or
less.
(3) For a new unit, the initial performance evaluation shall be
completed no later than July 30, 2013, or 180 days after the date of
initial startup, whichever is later. For an existing unit, the initial
performance evaluation shall be completed no later than July 29, 2016.
(4) For purposes of collecting SO2 data, you must
operate the SO2 CEMS as specified in Sec. 63.7535(b). You
must use all the data collected during all periods in calculating data
averages and assessing compliance, except that you must exclude certain
data as specified in Sec. 63.7535(c). Periods when SO2 data
are unavailable may constitute monitoring deviations as specified in
Sec. 63.7535(d).
(5) Collect CEMS hourly averages for all operating hours on a 30-
day rolling average basis.
(6) Use only unadjusted, quality-assured SO2
concentration values in the emissions calculations; do not apply bias
adjustment factors to the part 75 SO2 data and do not use
part 75 substitute data values.
0
18. Section 63.7530 is amended by:
0
a. Revising paragraph (a).
0
b. Revising paragraph (b) introductory text.
0
c. Redesignating paragraph (b)(3) as paragraph (b)(4) and adding new
paragraph (b)(3).
0
d. Revising newly designated paragraph (b)(4).
0
e. Revising paragraph (c), (c)(2) through (4).
0
f. Adding paragraph (c)(5).
0
g. Revising paragraphs (d), (e), (g), and (h).
0
h. Adding paragraph (i).
The revisions and additions read as follows:
Sec. 63.7530 How do I demonstrate initial compliance with the
emission limitations, fuel specifications and work practice standards?
(a) You must demonstrate initial compliance with each emission
limit that applies to you by conducting initial performance tests and
fuel analyses and establishing operating limits, as applicable,
according to Sec. 63.7520, paragraphs (b) and (c) of this section, and
Tables 5 and 7 to this subpart. The requirement to conduct a fuel
analysis is not applicable for units that burn a single type of fuel,
as specified by Sec. 63.7510(a)(2)(i). If applicable, you must also
install, operate, and maintain all applicable CMS (including CEMS,
COMS, and CPMS) according to Sec. 63.7525.
(b) If you demonstrate compliance through performance testing, you
must establish each site-specific operating limit in Table 4 to this
subpart that applies to you according to the requirements in Sec.
63.7520, Table 7 to this subpart, and paragraph (b)(4) of this section,
as applicable. You must also conduct fuel analyses according to Sec.
63.7521 and establish maximum fuel pollutant input levels according to
paragraphs (b)(1) through (3) of this section, as applicable, and as
specified in Sec. 63.7510(a)(2). (Note that Sec. 63.7510(a)(2)
exempts certain fuels from the fuel analysis requirements.) However, if
you switch fuel(s) and cannot show that the new fuel(s) does (do) not
increase the chlorine, mercury, or TSM input into the unit through the
results of fuel analysis, then you must repeat the performance test to
demonstrate compliance while burning the new fuel(s).
* * * * *
(3) If you opt to comply with the alternative TSM limit, you must
establish the maximum TSM fuel input (TSMinput) for solid or liquid
fuels during the initial fuel analysis according to the procedures in
paragraphs (b)(3)(i) through (iii) of this section.
(i) You must determine the fuel type or fuel mixture that you could
burn in your boiler or process heater that has the highest content of
TSM.
(ii) During the fuel analysis for TSM, you must determine the
fraction of the total heat input for each fuel type burned (Qi) based
on the fuel mixture that has the highest content of TSM, and the
average TSM concentration of each fuel type burned (TSMi).
(iii) You must establish a maximum TSM input level using Equation 9
of this section.
[GRAPHIC] [TIFF OMITTED] TR31JA13.013
Where:
TSMinput = Maximum amount of TSM entering the boiler or process
heater through fuels burned in units of pounds per million Btu.
TSMi = Arithmetic average concentration of TSM in fuel type, i,
analyzed according to Sec. 63.7521, in units of pounds per million
Btu.
Qi = Fraction of total heat input from fuel type, i, based on the
fuel mixture that has the highest content of TSM. If you do not burn
multiple fuel types during the performance testing, it is not
necessary to determine the value of this term. Insert a value of
``1'' for Qi.
n = Number of different fuel types burned in your boiler or process
heater for the mixture that has the highest content of TSM.
(4) You must establish parameter operating limits according to
paragraphs (b)(4)(i) through (ix) of this section. As indicated in
Table 4 to this subpart, you are not required to establish and comply
with the operating parameter limits when you are using a CEMS to
monitor and demonstrate compliance with the applicable emission limit
for that control device parameter.
(i) For a wet acid gas scrubber, you must establish the minimum
scrubber effluent pH and liquid flow rate as defined in Sec. 63.7575,
as your operating limits during the performance test during which you
demonstrate compliance with your applicable limit. If you use a wet
scrubber and you conduct separate performance tests for HCl and mercury
emissions, you must establish one set of minimum scrubber effluent pH,
liquid flow rate, and
[[Page 7175]]
pressure drop operating limits. The minimum scrubber effluent pH
operating limit must be established during the HCl performance test. If
you conduct multiple performance tests, you must set the minimum liquid
flow rate operating limit at the higher of the minimum values
established during the performance tests.
(ii) For any particulate control device (e.g., ESP, particulate wet
scrubber, fabric filter) for which you use a PM CPMS, you must
establish your PM CPMS operating limit and determine compliance with it
according to paragraphs (b)(4)(ii)(A) through (F) of this section.
(A) Determine your operating limit as the average PM CPMS output
value recorded during the most recent performance test run
demonstrating compliance with the filterable PM emission limit or at
the PM CPMS output value corresponding to 75 percent of the emission
limit if your PM performance test demonstrates compliance below 75
percent of the emission limit. You must verify an existing or establish
a new operating limit after each repeated performance test. You must
repeat the performance test annually and reassess and adjust the site-
specific operating limit in accordance with the results of the
performance test.
(1) Your PM CPMS must provide a 4-20 milliamp output and the
establishment of its relationship to manual reference method
measurements must be determined in units of milliamps.
(2) Your PM CPMS operating range must be capable of reading PM
concentrations from zero to a level equivalent to at least two times
your allowable emission limit. If your PM CPMS is an auto-ranging
instrument capable of multiple scales, the primary range of the
instrument must be capable of reading PM concentration from zero to a
level equivalent to two times your allowable emission limit.
(3) During the initial performance test or any such subsequent
performance test that demonstrates compliance with the PM limit, record
and average all milliamp output values from the PM CPMS for the periods
corresponding to the compliance test runs (e.g., average all your PM
CPMS output values for three corresponding 2-hour Method 5I test runs).
(B) If the average of your three PM performance test runs are below
75 percent of your PM emission limit, you must calculate an operating
limit by establishing a relationship of PM CPMS signal to PM
concentration using the PM CPMS instrument zero, the average PM CPMS
values corresponding to the three compliance test runs, and the average
PM concentration from the Method 5 or performance test with the
procedures in paragraphs (b)(4)(ii)(B)(1) through (4) of this section.
(1) Determine your instrument zero output with one of the following
procedures:
(i) Zero point data for in-situ instruments should be obtained by
removing the instrument from the stack and monitoring ambient air on a
test bench.
(ii) Zero point data for extractive instruments should be obtained
by removing the extractive probe from the stack and drawing in clean
ambient air.
(iii) The zero point may also be established by performing manual
reference method measurements when the flue gas is free of PM emissions
or contains very low PM concentrations (e.g., when your process is not
operating, but the fans are operating or your source is combusting only
natural gas) and plotting these with the compliance data to find the
zero intercept.
(iv) If none of the steps in paragraphs (b)(4)(ii)(B)(1)(i) through
(iii) of this section are possible, you must use a zero output value
provided by the manufacturer.
(2) Determine your PM CPMS instrument average in milliamps, and the
average of your corresponding three PM compliance test runs, using
equation 10.
[GRAPHIC] [TIFF OMITTED] TR31JA13.014
Where:
X1 = the PM CPMS data points for the three runs
constituting the performance test,
Y1 = the PM concentration value for the three runs
constituting the performance test, and
n = the number of data points.
(3) With your instrument zero expressed in milliamps, your three
run average PM CPMS milliamp value, and your three run average PM
concentration from your three compliance tests, determine a
relationship of lb/MMBtu per milliamp with equation 11.
[GRAPHIC] [TIFF OMITTED] TR31JA13.015
Where:
R = the relative lb/MMBtu per milliamp for your PM CPMS,
Y1 = the three run average lb/MMBtu PM concentration,
X1 = the three run average milliamp output from you PM
CPMS, and
z = the milliamp equivalent of your instrument zero determined from
(B)(i).
(4) Determine your source specific 30-day rolling average operating
limit using the lb/MMBtu per milliamp value from Equation 11 in
equation 12, below. This sets your operating limit at the PM CPMS
output value corresponding to 75 percent of your emission limit.
[GRAPHIC] [TIFF OMITTED] TR31JA13.016
Where:
Ol = the operating limit for your PM CPMS on a 30-day
rolling average, in milliamps.
L = your source emission limit expressed in lb/MMBtu,
z = your instrument zero in milliamps, determined from (B)(i), and
R = the relative lb/MMBtu per milliamp for your PM CPMS, from
Equation 11.
(C) If the average of your three PM compliance test runs is at or
above 75 percent of your PM emission limit you must determine your 30-
day rolling average operating limit by averaging the PM CPMS milliamp
output corresponding to your three PM performance test runs that
demonstrate compliance with the emission limit using equation 13 and
you must submit all compliance test and PM CPMS data according to the
reporting requirements in paragraph (b)(4)(ii)(F) of this section.
[GRAPHIC] [TIFF OMITTED] TR31JA13.017
Where:
X1 = the PM CPMS data points for all runs i,
n = the number of data points, and
Oh = your site specific operating limit, in milliamps.
(D) To determine continuous compliance, you must record the PM
[[Page 7176]]
CPMS output data for all periods when the process is operating and the
PM CPMS is not out-of-control. You must demonstrate continuous
compliance by using all quality-assured hourly average data collected
by the PM CPMS for all operating hours to calculate the arithmetic
average operating parameter in units of the operating limit (milliamps)
on a 30-day rolling average basis, updated at the end of each new
operating hour. Use Equation 14 to determine the 30-day rolling
average.
[GRAPHIC] [TIFF OMITTED] TR31JA13.018
Where:
30-day = 30-day average.
Hpvi = is the hourly parameter value for hour i
n = is the number of valid hourly parameter values collected over
the previous 720 operating hours.
(E) Use EPA Method 5 of appendix A to part 60 of this chapter to
determine PM emissions. For each performance test, conduct three
separate runs under the conditions that exist when the affected source
is operating at the highest load or capacity level reasonably expected
to occur. Conduct each test run to collect a minimum sample volume
specified in Tables 1, 2, or 11 through 13 to this subpart, as
applicable, for determining compliance with a new source limit or an
existing source limit. Calculate the average of the results from three
runs to determine compliance. You need not determine the PM collected
in the impingers (``back half'') of the Method 5 particulate sampling
train to demonstrate compliance with the PM standards of this subpart.
This shall not preclude the permitting authority from requiring a
determination of the ``back half'' for other purposes.
(F) For PM performance test reports used to set a PM CPMS operating
limit, the electronic submission of the test report must also include
the make and model of the PM CPMS instrument, serial number of the
instrument, analytical principle of the instrument (e.g. beta
attenuation), span of the instruments primary analytical range,
milliamp value equivalent to the instrument zero output, technique by
which this zero value was determined, and the average milliamp signals
corresponding to each PM compliance test run. (iii) For a particulate
wet scrubber, you must establish the minimum pressure drop and liquid
flow rate as defined in Sec. 63.7575, as your operating limits during
the three-run performance test during which you demonstrate compliance
with your applicable limit. If you use a wet scrubber and you conduct
separate performance tests for PM and TSM emissions, you must establish
one set of minimum scrubber liquid flow rate and pressure drop
operating limits. The minimum scrubber effluent pH operating limit must
be established during the HCl performance test. If you conduct multiple
performance tests, you must set the minimum liquid flow rate and
pressure drop operating limits at the higher of the minimum values
established during the performance tests.
(iii) For an electrostatic precipitator (ESP) operated with a wet
scrubber, you must establish the minimum total secondary electric power
input, as defined in Sec. 63.7575, as your operating limit during the
three-run performance test during which you demonstrate compliance with
your applicable limit. (These operating limits do not apply to ESP that
are operated as dry controls without a wet scrubber.)
(iv) For a dry scrubber, you must establish the minimum sorbent
injection rate for each sorbent, as defined in Sec. 63.7575, as your
operating limit during the three-run performance test during which you
demonstrate compliance with your applicable limit.
(v) For activated carbon injection, you must establish the minimum
activated carbon injection rate, as defined in Sec. 63.7575, as your
operating limit during the three-run performance test during which you
demonstrate compliance with your applicable limit.
(vi) The operating limit for boilers or process heaters with fabric
filters that demonstrate continuous compliance through bag leak
detection systems is that a bag leak detection system be installed
according to the requirements in Sec. 63.7525, and that each fabric
filter must be operated such that the bag leak detection system alert
is not activated more than 5 percent of the operating time during a 6-
month period.
(vii) For a minimum oxygen level, if you conduct multiple
performance tests, you must set the minimum oxygen level at the lower
of the minimum values established during the performance tests.
(viii) The operating limit for boilers or process heaters that
demonstrate continuous compliance with the HCl emission limit using a
SO2 CEMS is to install and operate the SO2
according to the requirements in Sec. 63.7525(m) establish a maximum
SO2 emission rate equal to the highest hourly average
SO2 measurement during the most recent three-run performance
test for HCl.
(c) If you elect to demonstrate compliance with an applicable
emission limit through fuel analysis, you must conduct fuel analyses
according to Sec. 63.7521 and follow the procedures in paragraphs
(c)(1) through (5) of this section.
* * * * *
(2) You must determine the 90th percentile confidence level fuel
pollutant concentration of the composite samples analyzed for each fuel
type using the one-sided t-statistic test described in Equation 15 of
this section.
[GRAPHIC] [TIFF OMITTED] TR31JA13.019
Where:
P90 = 90th percentile confidence level pollutant concentration, in
pounds per million Btu.
Mean = Arithmetic average of the fuel pollutant concentration in the
fuel samples analyzed according to Sec. 63.7521, in units of pounds
per million Btu.
SD = Standard deviation of the mean of pollutant concentration in
the fuel samples analyzed according to Sec. 63.7521, in units of
pounds per million Btu. SD is calculated as the sample standard
[[Page 7177]]
deviation divided by the square root of the number of samples.
t = t distribution critical value for 90th percentile
(t0.1) probability for the appropriate degrees of freedom
(number of samples minus one) as obtained from a t-Distribution
Critical Value Table.
(3) To demonstrate compliance with the applicable emission limit
for HCl, the HCl emission rate that you calculate for your boiler or
process heater using Equation 16 of this section must not exceed the
applicable emission limit for HCl.
[GRAPHIC] [TIFF OMITTED] TR31JA13.020
Where:
HCl = HCl emission rate from the boiler or process heater in units
of pounds per million Btu.
Ci90 = 90th percentile confidence level concentration of chlorine in
fuel type, i, in units of pounds per million Btu as calculated
according to Equation 11 of this section.
Qi = Fraction of total heat input from fuel type, i, based on the
fuel mixture that has the highest content of chlorine. If you do not
burn multiple fuel types, it is not necessary to determine the value
of this term. Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your boiler or process
heater for the mixture that has the highest content of chlorine.
1.028 = Molecular weight ratio of HCl to chlorine.
(4) To demonstrate compliance with the applicable emission limit
for mercury, the mercury emission rate that you calculate for your
boiler or process heater using Equation 17 of this section must not
exceed the applicable emission limit for mercury.
[GRAPHIC] [TIFF OMITTED] TR31JA13.021
Where:
Mercury = Mercury emission rate from the boiler or process heater in
units of pounds per million Btu.
Hgi90 = 90th percentile confidence level concentration of mercury in
fuel, i, in units of pounds per million Btu as calculated according
to Equation 11 of this section.
Qi = Fraction of total heat input from fuel type, i, based on the
fuel mixture that has the highest mercury content. If you do not
burn multiple fuel types, it is not necessary to determine the value
of this term. Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your boiler or process
heater for the mixture that has the highest mercury content.
(5) To demonstrate compliance with the applicable emission limit
for TSM for solid or liquid fuels, the TSM emission rate that you
calculate for your boiler or process heater from solid fuels using
Equation 18 of this section must not exceed the applicable emission
limit for TSM.
[GRAPHIC] [TIFF OMITTED] TR31JA13.022
Where:
Metals = TSM emission rate from the boiler or process heater in
units of pounds per million Btu.
TSMi90 = 90th percentile confidence level concentration of TSM in
fuel, i, in units of pounds per million Btu as calculated according
to Equation 11 of this section.
Qi = Fraction of total heat input from fuel type, i, based on the
fuel mixture that has the highest TSM content. If you do not burn
multiple fuel types, it is not necessary to determine the value of
this term. Insert a value of ``1'' for Qi.
n = Number of different fuel types burned in your boiler or process
heater for the mixture that has the highest TSM content.
(d) If you own or operate an existing unit with a heat input
capacity of less than 10 million Btu per hour or a unit in the unit
designed to burn gas 1 subcategory, you must submit a signed statement
in the Notification of Compliance Status report that indicates that you
conducted a tune-up of the unit.
(e) You must include with the Notification of Compliance Status a
signed certification that the energy assessment was completed according
to Table 3 to this subpart and is an accurate depiction of your
facility at the time of the assessment.
* * * * *
(g) If you elect to demonstrate that a gaseous fuel meets the
specifications of another gas 1 fuel as defined in Sec. 63.7575, you
must conduct an initial fuel specification analyses according to Sec.
63.7521(f) through (i) and according to the frequency listed in Sec.
63.7540(c) and maintain records of the results of the testing as
outlined in Sec. 63.7555(g). For samples where the initial mercury
specification has not been exceeded, you will include a signed
certification with the Notification of Compliance Status that the
initial fuel specification test meets the gas specification outlined in
the definition of other gas 1 fuels.
(h) If you own or operate a unit subject to emission limits in
Tables 1 or 2 or 11 through 13 to this subpart, you must meet the work
practice standard according to Table 3 of this subpart. During startup
and shutdown, you must only follow the work practice standards
according to item 5 of Table 3 of this subpart.
(i) If you opt to comply with the alternative SO2 CEMS
operating limit in Tables 4 and 8 to this subpart, you may do so only
if your affected boiler or process heater:
(1) Has a system using wet scrubber or dry sorbent injection and
SO2 CEMS installed on the unit; and
(2) At all times, you operate the wet scrubber or dry sorbent
injection for acid gas control on the unit consistent with Sec.
63.7500(a)(3); and
(3) You establish a unit-specific maximum SO2 operating
limit by
[[Page 7178]]
collecting the minimum hourly SO2 emission rate on the
SO2 CEMS during the paired 3-run test for HCl. The maximum
SO2 operating limit is equal to the highest hourly average
SO2 concentration measured during the most recent HCl
performance test.
0
19. Section 63.7533 is amended by:
0
a. Revising the section heading.
0
b. Revising paragraph (a).
0
c. Revising paragraphs (b)(1) and (4).
0
d. Revising paragraphs (c) introductory text, (c)(1)(i) and (ii),
(c)(2)(i), and (c)(3).
0
e. Revising paragraph (d) through (f).
0
f. Adding paragraph (g).
The revisions and addition read as follows:
Sec. 63.7533 Can I use efficiency credits earned from implementation
of energy conservation measures to comply with this subpart?
(a) If you elect to comply with the alternative equivalent output-
based emission limits, instead of the heat input-based limits listed in
Table 2 to this subpart, and you want to take credit for implementing
energy conservation measures identified in an energy assessment, you
may demonstrate compliance using efficiency credits according to the
procedures in this section. You may use this compliance approach for an
existing affected boiler for demonstrating initial compliance according
to Sec. 63.7522(e) and for demonstrating monthly compliance according
to Sec. 63.7522(f). Owners or operators using this compliance approach
must establish an emissions benchmark, calculate and document the
efficiency credits, develop an Implementation Plan, comply with the
general reporting requirements, and apply the efficiency credit
according to the procedures in paragraphs (b) through (f) of this
section. You cannot use this compliance approach for a new or
reconstructed affected boiler. Additional guidance from the Department
of Energy on efficiency credits is available at: https://www.epa.gov/ttn/atw/boiler/boilerpg.html.
(b) * * *
(1) The benchmark from which efficiency credits may be generated
shall be determined by using the most representative, accurate, and
reliable process available for the source. The benchmark shall be
established for a one-year period before the date that an energy demand
reduction occurs, unless it can be demonstrated that a different time
period is more representative of historical operations.
* * * * *
(4) Collect non-energy related facility and operational data to
normalize, if necessary, the benchmark to current operations, such as
building size, operating hours, etc. If possible, use actual data that
are current and timely rather than estimated data.
(c) Efficiency credits can be generated if the energy conservation
measures were implemented after January 1, 2008 and if sufficient
information is available to determine the appropriate value of credits.
(1) The following emission points cannot be used to generate
efficiency credits:
(i) Energy conservation measures implemented on or before January
1, 2008, unless the level of energy demand reduction is increased after
January 1, 2008, in which case credit will be allowed only for change
in demand reduction achieved after January 1, 2008.
(ii) Efficiency credits on shut-down boilers. Boilers that are shut
down cannot be used to generate credits unless the facility provides
documentation linking the permanent shutdown to energy conservation
measures identified in the energy assessment. In this case, the bench
established for the affected boiler to which the credits from the
shutdown will be applied must be revised to include the benchmark
established for the shutdown boiler.
(2) * * *
(i) Calculate annual credits for all energy demand points. Use
Equation 19 to calculate credits. Energy conservation measures that
meet the criteria of paragraph (c)(1) of this section shall not be
included, except as specified in paragraph (c)(1)(i) of this section.
* * * * *
(3) Credits are generated by the difference between the benchmark
that is established for each affected boiler, and the actual energy
demand reductions from energy conservation measures implemented after
January 1, 2008. Credits shall be calculated using Equation 19 of this
section as follows:
(i) The overall equation for calculating credits is:
[GRAPHIC] [TIFF OMITTED] TR31JA13.023
Where:
ECredits = Energy Input Savings for all energy conservation measures
implemented for an affected boiler, expressed as a decimal fraction
of the baseline energy input.
EISiactual = Energy Input Savings for each energy
conservation measure, i, implemented for an affected boiler, million
Btu per year.
EIbaseline = Energy Input baseline for the affected
boiler, million Btu per year.
n = Number of energy conservation measures included in the
efficiency credit for the affected boiler.
(ii) [Reserved]
(d) The owner or operator shall develop, and submit for approval
upon request by the Administrator, an Implementation Plan containing
all of the information required in this paragraph for all boilers to be
included in an efficiency credit approach. The Implementation Plan
shall identify all existing affected boilers to be included in applying
the efficiency credits. The Implementation Plan shall include a
description of the energy conservation measures implemented and the
energy savings generated from each measure and an explanation of the
criteria used for determining that savings. If requested, you must
submit the implementation plan for efficiency credits to the
Administrator for review and approval no later than 180 days before the
date on which the facility intends to demonstrate compliance using the
efficiency credit approach.
(e) The emissions rate as calculated using Equation 20 of this
section from each existing boiler participating in the efficiency
credit option must be in compliance with the limits in Table 2 to this
subpart at all times the affected unit is operating, following the
compliance date specified in Sec. 63.7495.
(f) You must use Equation 20 of this section to demonstrate initial
compliance by demonstrating that the emissions from the affected boiler
participating in the efficiency credit compliance approach do not
exceed the emission limits in Table 2 to this subpart.
[[Page 7179]]
[GRAPHIC] [TIFF OMITTED] TR31JA13.024
Where:
Eadj = Emission level adjusted by applying the efficiency
credits earned, lb per million Btu steam output (or lb per MWh) for
the affected boiler.
Em = Emissions measured during the performance test, lb
per million Btu steam output (or lb per MWh) for the affected
boiler.
ECredits = Efficiency credits from Equation 19 for the affected
boiler.
(g) As part of each compliance report submitted as required under
Sec. 63.7550, you must include documentation that the energy
conservation measures implemented continue to generate the credit for
use in demonstrating compliance with the emission limits.
0
20. Section 63.7535 is amended by revising the section heading and
paragraphs (b), (c), and (d) to read as follows:
Sec. 63.7535 Is there a minimum amount of monitoring data I must
obtain?
* * * * *
(b) You must operate the monitoring system and collect data at all
required intervals at all times that each boiler or process heater is
operating and compliance is required, except for periods of monitoring
system malfunctions or out of control periods (see Sec. 63.8(c)(7) of
this part), and required monitoring system quality assurance or control
activities, including, as applicable, calibration checks, required zero
and span adjustments, and scheduled CMS maintenance as defined in your
site-specific monitoring plan. A monitoring system malfunction is any
sudden, infrequent, not reasonably preventable failure of the
monitoring system to provide valid data. Monitoring system failures
that are caused in part by poor maintenance or careless operation are
not malfunctions. You are required to complete monitoring system
repairs in response to monitoring system malfunctions or out-of-control
periods and to return the monitoring system to operation as
expeditiously as practicable.
(c) You may not use data recorded during monitoring system
malfunctions or out-of-control periods, repairs associated with
monitoring system malfunctions or out-of-control periods, or required
monitoring system quality assurance or control activities in data
averages and calculations used to report emissions or operating levels.
You must record and make available upon request results of CMS
performance audits and dates and duration of periods when the CMS is
out of control to completion of the corrective actions necessary to
return the CMS to operation consistent with your site-specific
monitoring plan. You must use all the data collected during all other
periods in assessing compliance and the operation of the control device
and associated control system.
(d) Except for periods of monitoring system malfunctions, repairs
associated with monitoring system malfunctions, and required monitoring
system quality assurance or quality control activities (including, as
applicable, system accuracy audits, calibration checks, and required
zero and span adjustments), failure to collect required data is a
deviation of the monitoring requirements. In calculating monitoring
results, do not use any data collected during periods when the
monitoring system is out of control as specified in your site-specific
monitoring plan, while conducting repairs associated with periods when
the monitoring system is out of control, or while conducting required
monitoring system quality assurance or quality control activities. You
must calculate monitoring results using all other monitoring data
collected while the process is operating. You must report all periods
when the monitoring system is out of control in your annual report.
0
21. Section 63.7540 is revised to read as follows:
Sec. 63.7540 How do I demonstrate continuous compliance with the
emission limitations, fuel specifications and work practice standards?
(a) You must demonstrate continuous compliance with each emission
limit in Tables 1 and 2 or 11 through 13 to this subpart, the work
practice standards in Table 3 to this subpart, and the operating limits
in Table 4 to this subpart that applies to you according to the methods
specified in Table 8 to this subpart and paragraphs (a)(1) through (19)
of this section.
(1) Following the date on which the initial compliance
demonstration is completed or is required to be completed under
Sec. Sec. 63.7 and 63.7510, whichever date comes first, operation
above the established maximum or below the established minimum
operating limits shall constitute a deviation of established operating
limits listed in Table 4 of this subpart except during performance
tests conducted to determine compliance with the emission limits or to
establish new operating limits. Operating limits must be confirmed or
reestablished during performance tests.
(2) As specified in Sec. 63.7550(c), you must keep records of the
type and amount of all fuels burned in each boiler or process heater
during the reporting period to demonstrate that all fuel types and
mixtures of fuels burned would result in either of the following:
(i) Lower emissions of HCl, mercury, and TSM than the applicable
emission limit for each pollutant, if you demonstrate compliance
through fuel analysis.
(ii) Lower fuel input of chlorine, mercury, and TSM than the
maximum values calculated during the last performance test, if you
demonstrate compliance through performance testing.
(3) If you demonstrate compliance with an applicable HCl emission
limit through fuel analysis for a solid or liquid fuel and you plan to
burn a new type of solid or liquid fuel, you must recalculate the HCl
emission rate using Equation 12 of Sec. 63.7530 according to
paragraphs (a)(3)(i) through (iii) of this section. You are not
required to conduct fuel analyses for the fuels described in Sec.
63.7510(a)(2)(i) through (iii). You may exclude the fuels described in
Sec. 63.7510(a)(2)(i) through (iii) when recalculating the HCl
emission rate.
(i) You must determine the chlorine concentration for any new fuel
type in units of pounds per million Btu, based on supplier data or your
own fuel analysis, according to the provisions in your site-specific
fuel analysis plan developed according to Sec. 63.7521(b).
(ii) You must determine the new mixture of fuels that will have the
highest content of chlorine.
(iii) Recalculate the HCl emission rate from your boiler or process
heater under these new conditions using Equation 12 of Sec. 63.7530.
The recalculated HCl emission rate must be less than the applicable
emission limit.
(4) If you demonstrate compliance with an applicable HCl emission
limit through performance testing and you plan to burn a new type of
fuel or a new mixture of fuels, you must recalculate the maximum
chlorine input using Equation 7 of Sec. 63.7530. If the results of
recalculating the maximum chlorine input using Equation 7 of Sec.
63.7530 are greater than the maximum chlorine input level established
during the previous performance test, then you must conduct a new
performance test within 60 days of burning the new fuel type or fuel
mixture according to the
[[Page 7180]]
procedures in Sec. 63.7520 to demonstrate that the HCl emissions do
not exceed the emission limit. You must also establish new operating
limits based on this performance test according to the procedures in
Sec. 63.7530(b). In recalculating the maximum chlorine input and
establishing the new operating limits, you are not required to conduct
fuel analyses for and include the fuels described in Sec.
63.7510(a)(2)(i) through (iii).
(5) If you demonstrate compliance with an applicable mercury
emission limit through fuel analysis, and you plan to burn a new type
of fuel, you must recalculate the mercury emission rate using Equation
13 of Sec. 63.7530 according to the procedures specified in paragraphs
(a)(5)(i) through (iii) of this section. You are not required to
conduct fuel analyses for the fuels described in Sec. 63.7510(a)(2)(i)
through (iii). You may exclude the fuels described in Sec.
63.7510(a)(2)(i) through (iii) when recalculating the mercury emission
rate.
(i) You must determine the mercury concentration for any new fuel
type in units of pounds per million Btu, based on supplier data or your
own fuel analysis, according to the provisions in your site-specific
fuel analysis plan developed according to Sec. 63.7521(b).
(ii) You must determine the new mixture of fuels that will have the
highest content of mercury.
(iii) Recalculate the mercury emission rate from your boiler or
process heater under these new conditions using Equation 13 of Sec.
63.7530. The recalculated mercury emission rate must be less than the
applicable emission limit.
(6) If you demonstrate compliance with an applicable mercury
emission limit through performance testing, and you plan to burn a new
type of fuel or a new mixture of fuels, you must recalculate the
maximum mercury input using Equation 8 of Sec. 63.7530. If the results
of recalculating the maximum mercury input using Equation 8 of Sec.
63.7530 are higher than the maximum mercury input level established
during the previous performance test, then you must conduct a new
performance test within 60 days of burning the new fuel type or fuel
mixture according to the procedures in Sec. 63.7520 to demonstrate
that the mercury emissions do not exceed the emission limit. You must
also establish new operating limits based on this performance test
according to the procedures in Sec. 63.7530(b). You are not required
to conduct fuel analyses for the fuels described in Sec.
63.7510(a)(2)(i) through (iii). You may exclude the fuels described in
Sec. 63.7510(a)(2)(i) through (iii) when recalculating the mercury
emission rate.
(7) If your unit is controlled with a fabric filter, and you
demonstrate continuous compliance using a bag leak detection system,
you must initiate corrective action within 1 hour of a bag leak
detection system alert and complete corrective actions as soon as
practical, and operate and maintain the fabric filter system such that
the periods which would cause an alert are no more than 5 percent of
the operating time during a 6-month period. You must also keep records
of the date, time, and duration of each alert, the time corrective
action was initiated and completed, and a brief description of the
cause of the alert and the corrective action taken. You must also
record the percent of the operating time during each 6-month period
that the conditions exist for an alert. In calculating this operating
time percentage, if inspection of the fabric filter demonstrates that
no corrective action is required, no alert time is counted. If
corrective action is required, each alert shall be counted as a minimum
of 1 hour. If you take longer than 1 hour to initiate corrective
action, the alert time shall be counted as the actual amount of time
taken to initiate corrective action.
(8) To demonstrate compliance with the applicable alternative CO
CEMS emission limit listed in Tables 1, 2, or 11 through 13 to this
subpart, you must meet the requirements in paragraphs (a)(8)(i) through
(iv) of this section.
(i) Continuously monitor CO according to Sec. Sec. 63.7525(a) and
63.7535.
(ii) Maintain a CO emission level below or at your applicable
alternative CO CEMS-based standard in Tables 1 or 2 or 11 through 13 to
this subpart at all times the affected unit is operating.
(iii) Keep records of CO levels according to Sec. 63.7555(b).
(iv) You must record and make available upon request results of CO
CEMS performance audits, dates and duration of periods when the CO CEMS
is out of control to completion of the corrective actions necessary to
return the CO CEMS to operation consistent with your site-specific
monitoring plan.
(9) The owner or operator of a boiler or process heater using a PM
CPMS or a PM CEMS to meet requirements of this subpart shall install,
certify, operate, and maintain the PM CPMS or PM CEMS in accordance
with your site-specific monitoring plan as required in Sec.
63.7505(d).
(10) If your boiler or process heater has a heat input capacity of
10 million Btu per hour or greater, you must conduct an annual tune-up
of the boiler or process heater to demonstrate continuous compliance as
specified in paragraphs (a)(10)(i) through (vi) of this section. This
frequency does not apply to limited-use boilers and process heaters, as
defined in Sec. 63.7575, or units with continuous oxygen trim systems
that maintain an optimum air to fuel ratio.
(i) As applicable, inspect the burner, and clean or replace any
components of the burner as necessary (you may delay the burner
inspection until the next scheduled unit shutdown). Units that produce
electricity for sale may delay the burner inspection until the first
outage, not to exceed 36 months from the previous inspection. At units
where entry into a piece of process equipment or into a storage vessel
is required to complete the tune-up inspections, inspections are
required only during planned entries into the storage vessel or process
equipment;
(ii) Inspect the flame pattern, as applicable, and adjust the
burner as necessary to optimize the flame pattern. The adjustment
should be consistent with the manufacturer's specifications, if
available;
(iii) Inspect the system controlling the air-to-fuel ratio, as
applicable, and ensure that it is correctly calibrated and functioning
properly (you may delay the inspection until the next scheduled unit
shutdown). Units that produce electricity for sale may delay the
inspection until the first outage, not to exceed 36 months from the
previous inspection;
(iv) Optimize total emissions of CO. This optimization should be
consistent with the manufacturer's specifications, if available, and
with any NOX requirement to which the unit is subject;
(v) Measure the concentrations in the effluent stream of CO in
parts per million, by volume, and oxygen in volume percent, before and
after the adjustments are made (measurements may be either on a dry or
wet basis, as long as it is the same basis before and after the
adjustments are made). Measurements may be taken using a portable CO
analyzer; and
(vi) Maintain on-site and submit, if requested by the
Administrator, an annual report containing the information in
paragraphs (a)(10)(vi)(A) through (C) of this section,
(A) The concentrations of CO in the effluent stream in parts per
million by volume, and oxygen in volume percent, measured at high fire
or typical operating load, before and after the tune-up of the boiler
or process heater;
(B) A description of any corrective actions taken as a part of the
tune-up; and
[[Page 7181]]
(C) The type and amount of fuel used over the 12 months prior to
the tune-up, but only if the unit was physically and legally capable of
using more than one type of fuel during that period. Units sharing a
fuel meter may estimate the fuel used by each unit.
(11) If your boiler or process heater has a heat input capacity of
less than 10 million Btu per hour (except as specified in paragraph
(a)(12) of this section), you must conduct a biennial tune-up of the
boiler or process heater as specified in paragraphs (a)(10)(i) through
(vi) of this section to demonstrate continuous compliance.
(12) If your boiler or process heater has a continuous oxygen trim
system that maintains an optimum air to fuel ratio, or a heat input
capacity of less than or equal to 5 million Btu per hour and the unit
is in the units designed to burn gas 1; units designed to burn gas 2
(other); or units designed to burn light liquid subcategories, or meets
the definition of limited-use boiler or process heater in Sec.
63.7575, you must conduct a tune-up of the boiler or process heater
every 5 years as specified in paragraphs (a)(10)(i) through (vi) of
this section to demonstrate continuous compliance. You may delay the
burner inspection specified in paragraph (a)(10)(i) of this section
until the next scheduled or unscheduled unit shutdown, but you must
inspect each burner at least once every 72 months.
(13) If the unit is not operating on the required date for a tune-
up, the tune-up must be conducted within 30 calendar days of startup.
(14) If you are using a CEMS measuring mercury emissions to meet
requirements of this subpart you must install, certify, operate, and
maintain the mercury CEMS as specified in paragraphs (a)(14)(i) and
(ii) of this section.
(i) Operate the mercury CEMS in accordance with performance
specification 12A of 40 CFR part 60, appendix B or operate a sorbent
trap based integrated monitor in accordance with performance
specification 12B of 40 CFR part 60, appendix B. The duration of the
performance test must be the maximum of 30 unit operating days or 720
hours. For each day in which the unit operates, you must obtain hourly
mercury concentration data, and stack gas volumetric flow rate data.
(ii) If you are using a mercury CEMS, you must install, operate,
calibrate, and maintain an instrument for continuously measuring and
recording the mercury mass emissions rate to the atmosphere according
to the requirements of performance specifications 6 and 12A of 40 CFR
part 60, appendix B, and quality assurance procedure 6 of 40 CFR part
60, appendix F.
(15) If you are using a CEMS to measure HCl emissions to meet
requirements of this subpart, you must install, certify, operate, and
maintain the HCl CEMS as specified in paragraphs (a)(15)(i) and (ii) of
this section. This option for an affected unit takes effect on the date
a final performance specification for an HCl CEMS is published in the
Federal Register or the date of approval of a site-specific monitoring
plan.
(i) Operate the continuous emissions monitoring system in
accordance with the applicable performance specification in 40 CFR part
60, appendix B. The duration of the performance test must be the
maximum of 30 unit operating days or 720 hours. For each day in which
the unit operates, you must obtain hourly HCl concentration data, and
stack gas volumetric flow rate data.
(ii) If you are using a HCl CEMS, you must install, operate,
calibrate, and maintain an instrument for continuously measuring and
recording the HCl mass emissions rate to the atmosphere according to
the requirements of the applicable performance specification of 40 CFR
part 60, appendix B, and the quality assurance procedures of 40 CFR
part 60, appendix F.
(16) If you demonstrate compliance with an applicable TSM emission
limit through performance testing, and you plan to burn a new type of
fuel or a new mixture of fuels, you must recalculate the maximum TSM
input using Equation 9 of Sec. 63.7530. If the results of
recalculating the maximum TSM input using Equation 9 of Sec. 63.7530
are higher than the maximum total selected input level established
during the previous performance test, then you must conduct a new
performance test within 60 days of burning the new fuel type or fuel
mixture according to the procedures in Sec. 63.7520 to demonstrate
that the TSM emissions do not exceed the emission limit. You must also
establish new operating limits based on this performance test according
to the procedures in Sec. 63.7530(b). You are not required to conduct
fuel analyses for the fuels described in Sec. 63.7510(a)(2)(i) through
(iii). You may exclude the fuels described in Sec. 63.7510(a)(2)(i)
through (iii) when recalculating the TSM emission rate.
(17) If you demonstrate compliance with an applicable TSM emission
limit through fuel analysis for solid or liquid fuels, and you plan to
burn a new type of fuel, you must recalculate the TSM emission rate
using Equation 14 of Sec. 63.7530 according to the procedures
specified in paragraphs (a)(5)(i) through (iii) of this section. You
are not required to conduct fuel analyses for the fuels described in
Sec. 63.7510(a)(2)(i) through (iii). You may exclude the fuels
described in Sec. 63.7510(a)(2)(i) through (iii) when recalculating
the TSM emission rate.
(i) You must determine the TSM concentration for any new fuel type
in units of pounds per million Btu, based on supplier data or your own
fuel analysis, according to the provisions in your site-specific fuel
analysis plan developed according to Sec. 63.7521(b).
(ii) You must determine the new mixture of fuels that will have the
highest content of TSM.
(iii) Recalculate the TSM emission rate from your boiler or process
heater under these new conditions using Equation 14 of Sec. 63.7530.
The recalculated TSM emission rate must be less than the applicable
emission limit.
(18) If you demonstrate continuous PM emissions compliance with a
PM CPMS you will use a PM CPMS to establish a site-specific operating
limit corresponding to the results of the performance test
demonstrating compliance with the PM limit. You will conduct your
performance test using the test method criteria in Table 5 of this
subpart. You will use the PM CPMS to demonstrate continuous compliance
with this operating limit. You must repeat the performance test
annually and reassess and adjust the site-specific operating limit in
accordance with the results of the performance test.
(i) To determine continuous compliance, you must record the PM CPMS
output data for all periods when the process is operating and the PM
CPMS is not out-of-control. You must demonstrate continuous compliance
by using all quality-assured hourly average data collected by the PM
CPMS for all operating hours to calculate the arithmetic average
operating parameter in units of the operating limit (milliamps) on a
30-day rolling average basis, updated at the end of each new boiler or
process heater operating hour.
(ii) For any deviation of the 30-day rolling PM CPMS average value
from the established operating parameter limit, you must:
(A) Within 48 hours of the deviation, visually inspect the air
pollution control device (APCD);
(B) If inspection of the APCD identifies the cause of the
deviation, take corrective action as soon as possible and return the PM
CPMS measurement to within the established value; and
[[Page 7182]]
(C) Within 30 days of the deviation or at the time of the annual
compliance test, whichever comes first, conduct a PM emissions
compliance test to determine compliance with the PM emissions limit and
to verify or re-establish the CPMS operating limit. You are not
required to conduct additional testing for any deviations that occur
between the time of the original deviation and the PM emissions
compliance test required under this paragraph.
(iii) PM CPMS deviations from the operating limit leading to more
than four required performance tests in a 12-month operating period
constitute a separate violation of this subpart.
(19) If you choose to comply with the PM filterable emissions limit
by using PM CEMS you must install, certify, operate, and maintain a PM
CEMS and record the output of the PM CEMS as specified in paragraphs
(a)(19)(i) through (vii) of this section. The compliance limit will be
expressed as a 30-day rolling average of the numerical emissions limit
value applicable for your unit in Tables 1 or 2 or 11 through 13 of
this subpart.
(i) Install and certify your PM CEMS according to the procedures
and requirements in Performance Specification 11--Specifications and
Test Procedures for Particulate Matter Continuous Emission Monitoring
Systems at Stationary Sources in Appendix B to part 60 of this chapter,
using test criteria outlined in Table V of this rule. The reportable
measurement output from the PM CEMS must be expressed in units of the
applicable emissions limit (e.g., lb/MMBtu, lb/MWh).
(ii) Operate and maintain your PM CEMS according to the procedures
and requirements in Procedure 2-- Quality Assurance Requirements for
Particulate Matter Continuous Emission Monitoring Systems at Stationary
Sources in Appendix F to part 60 of this chapter.
(A) You must conduct the relative response audit (RRA) for your PM
CEMS at least once annually.
(B) You must conduct the relative correlation audit (RCA) for your
PM CEMS at least once every 3 years.
(iii) Collect PM CEMS hourly average output data for all boiler
operating hours except as indicated in paragraph (i) of this section.
(iv) Calculate the arithmetic 30-day rolling average of all of the
hourly average PM CEMS output data collected during all nonexempt
boiler or process heater operating hours.
(v) You must collect data using the PM CEMS at all times the unit
is operating and at the intervals specified this paragraph (a), except
for periods of monitoring system malfunctions, repairs associated with
monitoring system malfunctions, and required monitoring system quality
assurance or quality control activities.
(vi) You must use all the data collected during all boiler or
process heater operating hours in assessing the compliance with your
operating limit except:
(A) Any data collected during monitoring system malfunctions,
repairs associated with monitoring system malfunctions, or required
monitoring system quality assurance or control activities conducted
during monitoring system malfunctions in calculations and report any
such periods in your annual deviation report;
(B) Any data collected during periods when the monitoring system is
out of control as specified in your site-specific monitoring plan,
repairs associated with periods when the monitoring system is out of
control, or required monitoring system quality assurance or control
activities conducted during out of control periods in calculations used
to report emissions or operating levels and report any such periods in
your annual deviation report;
(C) Any data recorded during periods of startup or shutdown.
(vii) You must record and make available upon request results of PM
CEMS system performance audits, dates and duration of periods when the
PM CEMS is out of control to completion of the corrective actions
necessary to return the PM CEMS to operation consistent with your site-
specific monitoring plan.
(b) You must report each instance in which you did not meet each
emission limit and operating limit in Tables 1 through 4 or 11 through
13 to this subpart that apply to you. These instances are deviations
from the emission limits or operating limits, respectively, in this
subpart. These deviations must be reported according to the
requirements in Sec. 63.7550.
(c) If you elected to demonstrate that the unit meets the
specification for mercury for the unit designed to burn gas 1
subcategory, you must follow the sampling frequency specified in
paragraphs (c)(1) through (4) of this section and conduct this sampling
according to the procedures in Sec. 63.7521(f) through (i).
(1) If the initial mercury constituents in the gaseous fuels are
measured to be equal to or less than half of the mercury specification
as defined in Sec. 63.7575, you do not need to conduct further
sampling.
(2) If the initial mercury constituents are greater than half but
equal to or less than 75 percent of the mercury specification as
defined in Sec. 63.7575, you will conduct semi-annual sampling. If 6
consecutive semi-annual fuel analyses demonstrate 50 percent or less of
the mercury specification, you do not need to conduct further sampling.
If any semi-annual sample exceeds 75 percent of the mercury
specification, you must return to monthly sampling for that fuel, until
12 months of fuel analyses again are less than 75 percent of the
compliance level.
(3) If the initial mercury constituents are greater than 75 percent
of the mercury specification as defined in Sec. 63.7575, you will
conduct monthly sampling. If 12 consecutive monthly fuel analyses
demonstrate 75 percent or less of the mercury specification, you may
decrease the fuel analysis frequency to semi-annual for that fuel.
(4) If the initial sample exceeds the mercury specification as
defined in Sec. 63.7575, each affected boiler or process heater
combusting this fuel is not part of the unit designed to burn gas 1
subcategory and must be in compliance with the emission and operating
limits for the appropriate subcategory. You may elect to conduct
additional monthly sampling while complying with these emissions and
operating limits to demonstrate that the fuel qualifies as another gas
1 fuel. If 12 consecutive monthly fuel analyses samples are at or below
the mercury specification as defined in Sec. 63.7575, each affected
boiler or process heater combusting the fuel can elect to switch back
into the unit designed to burn gas 1 subcategory until the mercury
specification is exceeded.
(d) For startup and shutdown, you must meet the work practice
standards according to item 5 of Table 3 of this subpart.
0
22. Section 63.7541 is amended by revising paragraphs (a)(3) and (4) to
read as follows:
Sec. 63.7541 How do I demonstrate continuous compliance under the
emissions averaging provision?
* * * * *
(a) * * *
(3) For each existing unit participating in the emissions averaging
option that is equipped with a wet scrubber, maintain the 30-day
rolling average parameter values at or above the operating limits
established during the most recent performance test.
(4) For each existing unit participating in the emissions averaging
option that has an approved alternative operating parameter, maintain
the 30-day rolling
[[Page 7183]]
average parameter values consistent with the approved monitoring plan.
* * * * *
0
23. Section 63.7545 is amended by:
0
a. Revising paragraphs (a) through (c).
0
b. Revising paragraphs (e) introductory text, (e)(1), (e)(2), (e)(3),
(e)(4), (e)(5) introductory text, and (e)(5)(i).
0
c. Adding paragraph (e)(5)(ii).
0
d. Revising paragraphs (e)(8)(i) and (iii).
0
e. Revising paragraph (f) introductory text.
0
f. Revising paragraphs (g)(1) and (2).
0
g. Revising paragraphs (h) introductory text and (h)(1) and (3).
0
h. Removing paragraph (h)(4).
The revisions and addition read as follows:
Sec. 63.7545 What notifications must I submit and when?
(a) You must submit to the Administrator all of the notifications
in Sec. Sec. 63.7(b) and (c), 63.8(e), (f)(4) and (6), and 63.9(b)
through (h) that apply to you by the dates specified.
(b) As specified in Sec. 63.9(b)(2), if you startup your affected
source before January 31, 2013, you must submit an Initial Notification
not later than 120 days after January 31, 2013.
(c) As specified in Sec. 63.9(b)(4) and (5), if you startup your
new or reconstructed affected source on or after January 31, 2013, you
must submit an Initial Notification not later than 15 days after the
actual date of startup of the affected source.
* * * * *
(e) If you are required to conduct an initial compliance
demonstration as specified in Sec. 63.7530, you must submit a
Notification of Compliance Status according to Sec. 63.9(h)(2)(ii).
For the initial compliance demonstration for each boiler or process
heater, you must submit the Notification of Compliance Status,
including all performance test results and fuel analyses, before the
close of business on the 60th day following the completion of all
performance test and/or other initial compliance demonstrations for all
boiler or process heaters at the facility according to Sec.
63.10(d)(2). The Notification of Compliance Status report must contain
all the information specified in paragraphs (e)(1) through (8), as
applicable. If you are not required to conduct an initial compliance
demonstration as specified in Sec. 63.7530(a), the Notification of
Compliance Status must only contain the information specified in
paragraphs (e)(1) and (8).
(1) A description of the affected unit(s) including identification
of which subcategories the unit is in, the design heat input capacity
of the unit, a description of the add-on controls used on the unit to
comply with this subpart, description of the fuel(s) burned, including
whether the fuel(s) were a secondary material determined by you or the
EPA through a petition process to be a non-waste under Sec. 241.3 of
this chapter, whether the fuel(s) were a secondary material processed
from discarded non-hazardous secondary materials within the meaning of
Sec. 241.3 of this chapter, and justification for the selection of
fuel(s) burned during the compliance demonstration.
(2) Summary of the results of all performance tests and fuel
analyses, and calculations conducted to demonstrate initial compliance
including all established operating limits, and including:
(i) Identification of whether you are complying with the PM
emission limit or the alternative TSM emission limit.
(ii) Identification of whether you are complying with the output-
based emission limits or the heat input-based (i.e., lb/MMBtu or ppm)
emission limits,
(3) A summary of the maximum CO emission levels recorded during the
performance test to show that you have met any applicable emission
standard in Tables 1, 2, or 11 through 13 to this subpart, if you are
not using a CO CEMS to demonstrate compliance.
(4) Identification of whether you plan to demonstrate compliance
with each applicable emission limit through performance testing, a
CEMS, or fuel analysis.
(5) Identification of whether you plan to demonstrate compliance by
emissions averaging and identification of whether you plan to
demonstrate compliance by using efficiency credits through energy
conservation:
(i) If you plan to demonstrate compliance by emission averaging,
report the emission level that was being achieved or the control
technology employed on January 31, 2013.
(ii) [Reserved]
* * * * *
(8) * * *
(i) ``This facility complies with the required initial tune-up
according to the procedures in Sec. 63.7540(a)(10)(i) through (vi).''
* * * * *
(iii) Except for units that burn only natural gas, refinery gas, or
other gas 1 fuel, or units that qualify for a statutory exemption as
provided in section 129(g)(1) of the Clean Air Act, include the
following: ``No secondary materials that are solid waste were combusted
in any affected unit.''
(f) If you operate a unit designed to burn natural gas, refinery
gas, or other gas 1 fuels that is subject to this subpart, and you
intend to use a fuel other than natural gas, refinery gas, gaseous fuel
subject to another subpart of this part, part 60, 61, or 65, or other
gas 1 fuel to fire the affected unit during a period of natural gas
curtailment or supply interruption, as defined in Sec. 63.7575, you
must submit a notification of alternative fuel use within 48 hours of
the declaration of each period of natural gas curtailment or supply
interruption, as defined in Sec. 63.7575. The notification must
include the information specified in paragraphs (f)(1) through (5) of
this section.
* * * * *
(g) * * *
(1) The name of the owner or operator of the affected source, as
defined in Sec. 63.7490, the location of the source, the boiler(s) or
process heater(s) that will commence burning solid waste, and the date
of the notice.
(2) The currently applicable subcategories under this subpart.
* * * * *
(h) If you have switched fuels or made a physical change to the
boiler and the fuel switch or physical change resulted in the
applicability of a different subcategory, you must provide notice of
the date upon which you switched fuels or made the physical change
within 30 days of the switch/change. The notification must identify:
(1) The name of the owner or operator of the affected source, as
defined in Sec. 63.7490, the location of the source, the boiler(s) and
process heater(s) that have switched fuels, were physically changed,
and the date of the notice.
* * * * *
(3) The date upon which the fuel switch or physical change
occurred.
0
24. Section 63.7550 is revised to read as follows:
Sec. 63.7550 What reports must I submit and when?
(a) You must submit each report in Table 9 to this subpart that
applies to you.
(b) Unless the EPA Administrator has approved a different schedule
for submission of reports under Sec. 63.10(a), you must submit each
report, according to paragraph (h) of this section, by the date in
Table 9 to this subpart and according to the requirements in paragraphs
(b)(1) through (4) of this section. For units that are subject only to
a requirement to conduct an annual, biennial, or 5-year tune-up
according to Sec. 63.7540(a)(10), (11), or (12), respectively, and not
subject to emission
[[Page 7184]]
limits or operating limits, you may submit only an annual, biennial, or
5-year compliance report, as applicable, as specified in paragraphs
(b)(1) through (4) of this section, instead of a semi-annual compliance
report.
(1) The first compliance report must cover the period beginning on
the compliance date that is specified for each boiler or process heater
in Sec. 63.7495 and ending on July 31 or January 31, whichever date is
the first date that occurs at least 180 days (or 1, 2, or 5 years, as
applicable, if submitting an annual, biennial, or 5-year compliance
report) after the compliance date that is specified for your source in
Sec. 63.7495.
(2) The first compliance report must be postmarked or submitted no
later than July 31 or January 31, whichever date is the first date
following the end of the first calendar half after the compliance date
that is specified for each boiler or process heater in Sec. 63.7495.
The first annual, biennial, or 5-year compliance report must be
postmarked or submitted no later than January 31.
(3) Each subsequent compliance report must cover the semiannual
reporting period from January 1 through June 30 or the semiannual
reporting period from July 1 through December 31. Annual, biennial, and
5-year compliance reports must cover the applicable 1-, 2-, or 5-year
periods from January 1 to December 31.
(4) Each subsequent compliance report must be postmarked or
submitted no later than July 31 or January 31, whichever date is the
first date following the end of the semiannual reporting period.
Annual, biennial, and 5-year compliance reports must be postmarked or
submitted no later than January 31.
(c) A compliance report must contain the following information
depending on how the facility chooses to comply with the limits set in
this rule.
(1) If the facility is subject to a the requirements of a tune up
they must submit a compliance report with the information in paragraphs
(c)(5)(i) through (iv) and (xiv) of this section.
(2) If a facility is complying with the fuel analysis they must
submit a compliance report with the information in paragraphs (c)(5)(i)
through (iv), (vi), (x), (xi), (xiii), (xv) and paragraph (d) of this
section.
(3) If a facility is complying with the applicable emissions limit
with performance testing they must submit a compliance report with the
information in (c)(5)(i) through (iv), (vi), (vii), (ix), (xi), (xiii),
(xv) and paragraph (d) of this section.
(4) If a facility is complying with an emissions limit using a CMS
the compliance report must contain the information required in
paragraphs (c)(5)(i) through (vi), (xi), (xiii), (xv) through (xvii),
and paragraph (e) of this section.
(5)(i) Company and Facility name and address.
(ii) Process unit information, emissions limitations, and operating
parameter limitations.
(iii) Date of report and beginning and ending dates of the
reporting period.
(iv) The total operating time during the reporting period.
(v) If you use a CMS, including CEMS, COMS, or CPMS, you must
include the monitoring equipment manufacturer(s) and model numbers and
the date of the last CMS certification or audit.
(vi) The total fuel use by each individual boiler or process heater
subject to an emission limit within the reporting period, including,
but not limited to, a description of the fuel, whether the fuel has
received a non-waste determination by the EPA or your basis for
concluding that the fuel is not a waste, and the total fuel usage
amount with units of measure.
(vii) If you are conducting performance tests once every 3 years
consistent with Sec. 63.7515(b) or (c), the date of the last 2
performance tests and a statement as to whether there have been any
operational changes since the last performance test that could increase
emissions.
(viii) A statement indicating that you burned no new types of fuel
in an individual boiler or process heater subject to an emission limit.
Or, if you did burn a new type of fuel and are subject to a HCl
emission limit, you must submit the calculation of chlorine input,
using Equation 7 of Sec. 63.7530, that demonstrates that your source
is still within its maximum chlorine input level established during the
previous performance testing (for sources that demonstrate compliance
through performance testing) or you must submit the calculation of HCl
emission rate using Equation 12 of Sec. 63.7530 that demonstrates that
your source is still meeting the emission limit for HCl emissions (for
boilers or process heaters that demonstrate compliance through fuel
analysis). If you burned a new type of fuel and are subject to a
mercury emission limit, you must submit the calculation of mercury
input, using Equation 8 of Sec. 63.7530, that demonstrates that your
source is still within its maximum mercury input level established
during the previous performance testing (for sources that demonstrate
compliance through performance testing), or you must submit the
calculation of mercury emission rate using Equation 13 of Sec. 63.7530
that demonstrates that your source is still meeting the emission limit
for mercury emissions (for boilers or process heaters that demonstrate
compliance through fuel analysis). If you burned a new type of fuel and
are subject to a TSM emission limit, you must submit the calculation of
TSM input, using Equation 9 of Sec. 63.7530, that demonstrates that
your source is still within its maximum TSM input level established
during the previous performance testing (for sources that demonstrate
compliance through performance testing), or you must submit the
calculation of TSM emission rate, using Equation 14 of Sec. 63.7530,
that demonstrates that your source is still meeting the emission limit
for TSM emissions (for boilers or process heaters that demonstrate
compliance through fuel analysis).
(ix) If you wish to burn a new type of fuel in an individual boiler
or process heater subject to an emission limit and you cannot
demonstrate compliance with the maximum chlorine input operating limit
using Equation 7 of Sec. 63.7530 or the maximum mercury input
operating limit using Equation 8 of Sec. 63.7530, or the maximum TSM
input operating limit using Equation 9 of Sec. 63.7530 you must
include in the compliance report a statement indicating the intent to
conduct a new performance test within 60 days of starting to burn the
new fuel.
(x) A summary of any monthly fuel analyses conducted to demonstrate
compliance according to Sec. Sec. 63.7521 and 63.7530 for individual
boilers or process heaters subject to emission limits, and any fuel
specification analyses conducted according to Sec. Sec. 63.7521(f) and
63.7530(g).
(xi) If there are no deviations from any emission limits or
operating limits in this subpart that apply to you, a statement that
there were no deviations from the emission limits or operating limits
during the reporting period.
(xii) If there were no deviations from the monitoring requirements
including no periods during which the CMSs, including CEMS, COMS, and
CPMS, were out of control as specified in Sec. 63.8(c)(7), a statement
that there were no deviations and no periods during which the CMS were
out of control during the reporting period.
(xiii) If a malfunction occurred during the reporting period, the
report must include the number, duration, and a brief description for
each type of malfunction which occurred during the reporting period and
which caused or
[[Page 7185]]
may have caused any applicable emission limitation to be exceeded. The
report must also include a description of actions taken by you during a
malfunction of a boiler, process heater, or associated air pollution
control device or CMS to minimize emissions in accordance with Sec.
63.7500(a)(3), including actions taken to correct the malfunction.
(xiv) Include the date of the most recent tune-up for each unit
subject to only the requirement to conduct an annual, biennial, or 5-
year tune-up according to Sec. 63.7540(a)(10), (11), or (12)
respectively. Include the date of the most recent burner inspection if
it was not done annually, biennially, or on a 5-year period and was
delayed until the next scheduled or unscheduled unit shutdown.
(xv) If you plan to demonstrate compliance by emission averaging,
certify the emission level achieved or the control technology employed
is no less stringent than the level or control technology contained in
the notification of compliance status in Sec. 63.7545(e)(5)(i).
(xvi) For each reporting period, the compliance reports must
include all of the calculated 30 day rolling average values based on
the daily CEMS (CO and mercury) and CPMS (PM CPMS output, scrubber pH,
scrubber liquid flow rate, scrubber pressure drop) data.
(xvii) Statement by a responsible official with that official's
name, title, and signature, certifying the truth, accuracy, and
completeness of the content of the report.
(d) For each deviation from an emission limit or operating limit in
this subpart that occurs at an individual boiler or process heater
where you are not using a CMS to comply with that emission limit or
operating limit, the compliance report must additionally contain the
information required in paragraphs (d)(1) through (3) of this section.
(1) A description of the deviation and which emission limit or
operating limit from which you deviated.
(2) Information on the number, duration, and cause of deviations
(including unknown cause), as applicable, and the corrective action
taken.
(3) If the deviation occurred during an annual performance test,
provide the date the annual performance test was completed.
(e) For each deviation from an emission limit, operating limit, and
monitoring requirement in this subpart occurring at an individual
boiler or process heater where you are using a CMS to comply with that
emission limit or operating limit, the compliance report must
additionally contain the information required in paragraphs (e)(1)
through (9) of this section. This includes any deviations from your
site-specific monitoring plan as required in Sec. 63.7505(d).
(1) The date and time that each deviation started and stopped and
description of the nature of the deviation (i.e., what you deviated
from).
(2) The date and time that each CMS was inoperative, except for
zero (low-level) and high-level checks.
(3) The date, time, and duration that each CMS was out of control,
including the information in Sec. 63.8(c)(8).
(4) The date and time that each deviation started and stopped.
(5) A summary of the total duration of the deviation during the
reporting period and the total duration as a percent of the total
source operating time during that reporting period.
(6) A characterization of the total duration of the deviations
during the reporting period into those that are due to control
equipment problems, process problems, other known causes, and other
unknown causes.
(7) A summary of the total duration of CMS's downtime during the
reporting period and the total duration of CMS downtime as a percent of
the total source operating time during that reporting period.
(8) A brief description of the source for which there was a
deviation.
(9) A description of any changes in CMSs, processes, or controls
since the last reporting period for the source for which there was a
deviation.
(f) [Reserved]
(g) [Reserved]
(h) You must submit the reports according to the procedures
specified in paragraphs (h)(1) through (3) of this section.
(1) Within 60 days after the date of completing each performance
test (defined in Sec. 63.2) as required by this subpart you must
submit the results of the performance tests, including any associated
fuel analyses, required by this subpart and the compliance reports
required in Sec. 63.7550(b) to the EPA's WebFIRE database by using the
Compliance and Emissions Data Reporting Interface (CEDRI) that is
accessed through the EPA's Central Data Exchange (CDX) (www.epa.gov/cdx). Performance test data must be submitted in the file format
generated through use of the EPA's Electronic Reporting Tool (ERT) (see
https://www.epa.gov/ttn/chief/ert/). Only data collected using
test methods on the ERT Web site are subject to this requirement for
submitting reports electronically to WebFIRE. Owners or operators who
claim that some of the information being submitted for performance
tests is confidential business information (CBI) must submit a complete
ERT file including information claimed to be CBI on a compact disk or
other commonly used electronic storage media (including, but not
limited to, flash drives) to the EPA. The electronic media must be
clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office,
Attention: WebFIRE Administrator, MD C404-02, 4930 Old Page Rd.,
Durham, NC 27703. The same ERT file with the CBI omitted must be
submitted to the EPA via CDX as described earlier in this paragraph. At
the discretion of the Administrator, you must also submit these
reports, including the confidential business information, to the
Administrator in the format specified by the Administrator. For any
performance test conducted using test methods that are not listed on
the ERT Web site, the owner or operator shall submit the results of the
performance test in paper submissions to the Administrator.
(2) Within 60 days after the date of completing each CEMS
performance evaluation test (defined in 63.2) you must submit the
relative accuracy test audit (RATA) data to the EPA's Central Data
Exchange by using CEDRI as mentioned in paragraph (h)(1) of this
section. Only RATA pollutants that can be documented with the ERT (as
listed on the ERT Web site) are subject to this requirement. For any
performance evaluations with no corresponding RATA pollutants listed on
the ERT Web site, the owner or operator shall submit the results of the
performance evaluation in paper submissions to the Administrator.
(3) You must submit all reports required by Table 9 of this subpart
electronically using CEDRI that is accessed through the EPA's Central
Data Exchange (CDX) (www.epa.gov/cdx). However, if the reporting form
specific to this subpart is not available in CEDRI at the time that the
report is due the report you must submit the report to the
Administrator at the appropriate address listed in Sec. 63.13. At the
discretion of the Administrator, you must also submit these reports, to
the Administrator in the format specified by the Administrator.
0
25. Section 63.7555 is amended by:
0
a. Revising paragraphs (d) introductory text and (d)(2) through (6).
0
b. Adding paragraphs (d)(9) through (11).
0
c. Revising paragraphs (f) through (h).
0
d. Adding paragraphs (i) and (j).
[[Page 7186]]
The revisions and additions read as follows:
Sec. 63.7555 What records must I keep?
* * * * *
(d) For each boiler or process heater subject to an emission limit
in Tables 1, 2, or 11 through 13 to this subpart, you must also keep
the applicable records in paragraphs (d)(1) through (11) of this
section.
* * * * *
(2) If you combust non-hazardous secondary materials that have been
determined not to be solid waste pursuant to Sec. 241.3(b)(1) and (2)
of this chapter, you must keep a record that documents how the
secondary material meets each of the legitimacy criteria under Sec.
241.3(d)(1) of this chapter. If you combust a fuel that has been
processed from a discarded non-hazardous secondary material pursuant to
Sec. 241.3(b)(4) of this chapter, you must keep records as to how the
operations that produced the fuel satisfy the definition of processing
in Sec. 241.2 of this chapter. If the fuel received a non-waste
determination pursuant to the petition process submitted under Sec.
241.3(c) of this chapter, you must keep a record that documents how the
fuel satisfies the requirements of the petition process. For operating
units that combust non-hazardous secondary materials as fuel per Sec.
241.4 of this chapter, you must keep records documenting that the
material is listed as a non-waste under Sec. 241.4(a) of this chapter.
Units exempt from the incinerator standards under section 129(g)(1) of
the Clean Air Act because they are qualifying facilities burning a
homogeneous waste stream do not need to maintain the records described
in this paragraph (d)(2).
(3) For units in the limited use subcategory, you must keep a copy
of the federally enforceable permit that limits the annual capacity
factor to less than or equal to 10 percent and fuel use records for the
days the boiler or process heater was operating.
(4) A copy of all calculations and supporting documentation of
maximum chlorine fuel input, using Equation 7 of Sec. 63.7530, that
were done to demonstrate continuous compliance with the HCl emission
limit, for sources that demonstrate compliance through performance
testing. For sources that demonstrate compliance through fuel analysis,
a copy of all calculations and supporting documentation of HCl emission
rates, using Equation 12 of Sec. 63.7530, that were done to
demonstrate compliance with the HCl emission limit. Supporting
documentation should include results of any fuel analyses and basis for
the estimates of maximum chlorine fuel input or HCl emission rates. You
can use the results from one fuel analysis for multiple boilers and
process heaters provided they are all burning the same fuel type.
However, you must calculate chlorine fuel input, or HCl emission rate,
for each boiler and process heater.
(5) A copy of all calculations and supporting documentation of
maximum mercury fuel input, using Equation 8 of Sec. 63.7530, that
were done to demonstrate continuous compliance with the mercury
emission limit for sources that demonstrate compliance through
performance testing. For sources that demonstrate compliance through
fuel analysis, a copy of all calculations and supporting documentation
of mercury emission rates, using Equation 13 of Sec. 63.7530, that
were done to demonstrate compliance with the mercury emission limit.
Supporting documentation should include results of any fuel analyses
and basis for the estimates of maximum mercury fuel input or mercury
emission rates. You can use the results from one fuel analysis for
multiple boilers and process heaters provided they are all burning the
same fuel type. However, you must calculate mercury fuel input, or
mercury emission rates, for each boiler and process heater.
(6) If, consistent with Sec. 63.7515(b), you choose to stack test
less frequently than annually, you must keep a record that documents
that your emissions in the previous stack test(s) were less than 75
percent of the applicable emission limit (or, in specific instances
noted in Tables 1 and 2 or 11 through 13 to this subpart, less than the
applicable emission limit), and document that there was no change in
source operations including fuel composition and operation of air
pollution control equipment that would cause emissions of the relevant
pollutant to increase within the past year.
* * * * *
(9) A copy of all calculations and supporting documentation of
maximum TSM fuel input, using Equation 9 of Sec. 63.7530, that were
done to demonstrate continuous compliance with the TSM emission limit
for sources that demonstrate compliance through performance testing.
For sources that demonstrate compliance through fuel analysis, a copy
of all calculations and supporting documentation of TSM emission rates,
using Equation 14 of Sec. 63.7530, that were done to demonstrate
compliance with the TSM emission limit. Supporting documentation should
include results of any fuel analyses and basis for the estimates of
maximum TSM fuel input or TSM emission rates. You can use the results
from one fuel analysis for multiple boilers and process heaters
provided they are all burning the same fuel type. However, you must
calculate TSM fuel input, or TSM emission rates, for each boiler and
process heater.
(10) You must maintain records of the calendar date, time,
occurrence and duration of each startup and shutdown.
(11) You must maintain records of the type(s) and amount(s) of
fuels used during each startup and shutdown.
* * * * *
(f) If you elect to use efficiency credits from energy conservation
measures to demonstrate compliance according to Sec. 63.7533, you must
keep a copy of the Implementation Plan required in Sec. 63.7533(d) and
copies of all data and calculations used to establish credits according
to Sec. 63.7533(b), (c), and (f).
(g) If you elected to demonstrate that the unit meets the
specification for mercury for the unit designed to burn gas 1
subcategory, you must maintain monthly records (or at the frequency
required by Sec. 63.7540(c)) of the calculations and results of the
fuel specification for mercury in Table 6.
(h) If you operate a unit in the unit designed to burn gas 1
subcategory that is subject to this subpart, and you use an alternative
fuel other than natural gas, refinery gas, gaseous fuel subject to
another subpart under this part, other gas 1 fuel, or gaseous fuel
subject to another subpart of this part or part 60, 61, or 65, you must
keep records of the total hours per calendar year that alternative fuel
is burned and the total hours per calendar year that the unit operated
during periods of gas curtailment or gas supply emergencies.
(i) You must maintain records of the calendar date, time,
occurrence and duration of each startup and shutdown.
(j) You must maintain records of the type(s) and amount(s) of fuels
used during each startup and shutdown.
0
26. Section 63.7570 is amended by revising paragraph (a) and paragraph
(b) introductory text to read as follows:
Sec. 63.7570 Who implements and enforces this subpart?
(a) This subpart can be implemented and enforced by the EPA, or an
Administrator such as your state, local, or tribal agency. If the EPA
Administrator has delegated authority to your state, local, or tribal
agency, then that agency (as well as the EPA) has the authority to
implement and enforce this subpart. You should contact your EPA
Regional Office to find out if this
[[Page 7187]]
subpart is delegated to your state, local, or tribal agency.
(b) In delegating implementation and enforcement authority of this
subpart to a state, local, or tribal agency under 40 CFR part 63,
subpart E, the authorities listed in paragraphs (b)(1) through (5) of
this section are retained by the EPA Administrator and are not
transferred to the state, local, or tribal agency, however, the EPA
retains oversight of this subpart and can take enforcement actions, as
appropriate.
* * * * *
0
27. Section 63.7575 is amended by:
0
a. Adding in alphabetical order definitions for ``10-day rolling
average,'' ``30-day rolling average,'' ``Annual capacity factor,''
``Average annual heat input rate,'' ``Benchmark,'' ``Biodiesel,''
``Daily block average,'' ``Efficiency credit,'' ``Energy management
program,'' ``Fluidized bed boiler with an integrated fluidized bed heat
exchanger,'' ``Heavy liquid,'' ``Light liquid,'' '' ``Major source for
oil and natural gas production facilities,'' ``Minimum oxygen level,''
``Other combustor'', ``Oxygen analyzer system'', ``Oxygen trim
system'', ``Pile burner'', ``Regulated gas stream'', ``Residential
boiler,'' ``Residual oil'', ``Secondary material,'' ``Shutdown'',
``Sloped grate'', ``Startup'', ``Stoker/sloped grate/other unit
designed to burn kiln dried biomass,'' Stoker/sloped grate/other unit
designed to burn wet biomass,'' ``Suspension burner,'' ``Total selected
metals (TSM),'' ``Traditional fuel,'' ``Ultra low sulfur liquid fuel,''
``Unit designed to burn heavy liquid subcategory,'' ``Unit designed to
burn light liquid subcategory,'' and ``Vegetable oil.''
0
b. Revising the definitions for ``Boiler,'' ``Boiler system,''
``Coal,'' Commercial/institutional boiler,'' ``Deviation,''
``Distillate oil,'' ``Dry scrubber,'' ``Dutch oven,'' ``Electric
utility steam generating unit,'' ``Energy assessment,'' ``Energy use
system,'' ``Equivalent,'' ``Federally enforceable,'' ``Fluidized bed
boiler'', ``Fuel cell,'' ``Fuel type,'' ``Gaseous fuel,'' ``Heat
input,'' ``Hot water heater,'' ``Hybrid suspension grate boiler,''
``Industrial boiler,'' ``Limited-use boiler or process heater,''
``Liquid fuel,'' ``Load fraction,'' ``Metal process furnaces,''
``Minimum activated carbon injection rate,'' ``Minimum scrubber liquid
flow rate,'' ``Minimum sorbent injection rate,'' ``Natural gas,''
``Other gas 1 fuel,'' ``Period of natural gas curtailment or supply
interruption,'' ``Process heater,'' ``Qualified energy assessor,''
``Residual oil,'' ``Solid fossil fuel,'' ``Steam output,'' ``Stoker,''
``Temporary boiler,'' ``Tune-up,'' ``Unit designed to burn gas 1
subcategory,'' ``Unit designed to burn gas 2 (other) subcategory,''
``Unit designed to burn liquid subcategory,'' ``Unit designed to burn
liquid fuel that is a non-continental unit,'' ``Unit designed to burn
solid fuel,'' ``Waste heat boiler,'' ``Waste heat process heater.''
0
c. Removing the definitions for ``Benchmarking,'' ``Emission credit,''
``Liquid fuel subcategory,'' and ``Suspension boiler.''
The revisions read as follows:
Sec. 63.7575 What definitions apply to this subpart?
* * * * *
10-day rolling average means the arithmetic mean of the previous
240 hours of valid operating data. Valid data excludes hours during
startup and shutdown, data collected during periods when the monitoring
system is out of control as specified in your site-specific monitoring
plan, while conducting repairs associated with periods when the
monitoring system is out of control, or while conducting required
monitoring system quality assurance or quality control activities, and
periods when this unit is not operating. The 240 hours should be
consecutive, but not necessarily continuous if operations were
intermittent.
30-day rolling average means the arithmetic mean of the previous
720 hours of valid operating data. Valid data excludes hours during
startup and shutdown, data collected during periods when the monitoring
system is out of control as specified in your site-specific monitoring
plan, while conducting repairs associated with periods when the
monitoring system is out of control, or while conducting required
monitoring system quality assurance or quality control activities, and
periods when this unit is not operating. The 720 hours should be
consecutive, but not necessarily continuous if operations were
intermittent.
* * * * *
Annual capacity factor means the ratio between the actual heat
input to a boiler or process heater from the fuels burned during a
calendar year and the potential heat input to the boiler or process
heater had it been operated for 8,760 hours during a year at the
maximum steady state design heat input capacity.
Average annual heat input rate means total heat input divided by
the hours of operation for the 12 months preceding the compliance
demonstration.
* * * * *
Benchmark means the fuel heat input for a boiler or process heater
for the one-year period before the date that an energy demand reduction
occurs, unless it can be demonstrated that a different time period is
more representative of historical operations.
Biodiesel means a mono-alkyl ester derived from biomass and
conforming to ASTM D6751-11b, Standard Specification for Biodiesel Fuel
Blend Stock (B100) for Middle Distillate Fuels (incorporated by
reference, see Sec. 63.14).
* * * * *
Boiler means an enclosed device using controlled flame combustion
and having the primary purpose of recovering thermal energy in the form
of steam or hot water. Controlled flame combustion refers to a steady-
state, or near steady-state, process wherein fuel and/or oxidizer feed
rates are controlled. A device combusting solid waste, as defined in
Sec. 241.3 of this chapter, is not a boiler unless the device is
exempt from the definition of a solid waste incineration unit as
provided in section 129(g)(1) of the Clean Air Act. Waste heat boilers
are excluded from this definition.
Boiler system means the boiler and associated components, such as,
the feed water system, the combustion air system, the fuel system
(including burners), blowdown system, combustion control systems, steam
systems, and condensate return systems.
* * * * *
Coal means all solid fuels classifiable as anthracite, bituminous,
sub-bituminous, or lignite by ASTM D388 (incorporated by reference, see
Sec. 63.14), coal refuse, and petroleum coke. For the purposes of this
subpart, this definition of ``coal'' includes synthetic fuels derived
from coal, including but not limited to, solvent-refined coal, coal-oil
mixtures, and coal-water mixtures. Coal derived gases are excluded from
this definition.
* * * * *
Commercial/institutional boiler means a boiler used in commercial
establishments or institutional establishments such as medical centers,
nursing homes, research centers, institutions of higher education,
elementary and secondary schools, libraries, religious establishments,
governmental buildings, hotels, restaurants, and laundries to provide
electricity, steam, and/or hot water.
* * * * *
Daily block average means the arithmetic mean of all valid emission
concentrations or parameter levels recorded when a unit is operating
measured over the 24-hour period from 12 a.m. (midnight) to 12 a.m.
(midnight), except for periods of startup and shutdown or downtime.
[[Page 7188]]
Deviation.
(1) Deviation means any instance in which an affected source
subject to this subpart, or an owner or operator of such a source:
(i) Fails to meet any applicable requirement or obligation
established by this subpart including, but not limited to, any emission
limit, operating limit, or work practice standard; or
(ii) Fails to meet any term or condition that is adopted to
implement an applicable requirement in this subpart and that is
included in the operating permit for any affected source required to
obtain such a permit.
(2) A deviation is not always a violation.
* * * * *
Distillate oil means fuel oils that contain 0.05 weight percent
nitrogen or less and comply with the specifications for fuel oil
numbers 1 and 2, as defined by the American Society of Testing and
Materials in ASTM D396 (incorporated by reference, see Sec. 63.14) or
diesel fuel oil numbers 1 and 2, as defined by the American Society for
Testing and Materials in ASTM D975 (incorporated by reference, see
Sec. 63.14), kerosene, and biodiesel as defined by the American
Society of Testing and Materials in ASTM D6751-11b (incorporated by
reference, see Sec. 60.14).
Dry scrubber means an add-on air pollution control system that
injects dry alkaline sorbent (dry injection) or sprays an alkaline
sorbent (spray dryer) to react with and neutralize acid gas in the
exhaust stream forming a dry powder material. Sorbent injection systems
used as control devices in fluidized bed boilers and process heaters
are included in this definition. A dry scrubber is a dry control
system.
Dutch oven means a unit having a refractory-walled cell connected
to a conventional boiler setting. Fuel materials are introduced through
an opening in the roof of the dutch oven and burn in a pile on its
floor. Fluidized bed boilers are not part of the dutch oven design
category.
Electric utility steam generating unit (EGU) means a fossil fuel-
fired combustion unit of more than 25 megawatts electric (MWe) that
serves a generator that produces electricity for sale. A fossil fuel-
fired unit that cogenerates steam and electricity and supplies more
than one-third of its potential electric output capacity and more than
25 MWe output to any utility power distribution system for sale is
considered an electric utility steam generating unit. To be ``capable
of combusting'' fossil fuels, an EGU would need to have these fuels
allowed in their operating permits and have the appropriate fuel
handling facilities on-site or otherwise available (e.g., coal handling
equipment, including coal storage area, belts and conveyers,
pulverizers, etc.; oil storage facilities). In addition, fossil fuel-
fired EGU means any EGU that fired fossil fuel for more than 10.0
percent of the average annual heat input in any 3 consecutive calendar
years or for more than 15.0 percent of the annual heat input during any
one calendar year after April 16, 2012.
* * * * *
Efficiency credit means emission reductions above those required by
this subpart. Efficiency credits generated may be used to comply with
the emissions limits. Credits may come from pollution prevention
projects that result in reduced fuel use by affected units. Boilers
that are shut down cannot be used to generate credits unless the
facility provides documentation linking the permanent shutdown to
implementation of the energy conservation measures identified in the
energy assessment.
Energy assessment means the following for the emission units
covered by this subpart:
(1) The energy assessment for facilities with affected boilers and
process heaters with a combined heat input capacity of less than 0.3
trillion Btu (TBtu) per year will be 8 on-site technical labor hours in
length maximum, but may be longer at the discretion of the owner or
operator of the affected source. The boiler system(s) and any on-site
energy use system(s) accounting for at least 50 percent of the affected
boiler(s) energy (e.g., steam, hot water, process heat, or electricity)
production, as applicable, will be evaluated to identify energy savings
opportunities, within the limit of performing an 8-hour on-site energy
assessment.
(2) The energy assessment for facilities with affected boilers and
process heaters with a combined heat input capacity of 0.3 to 1.0 TBtu/
year will be 24 on-site technical labor hours in length maximum, but
may be longer at the discretion of the owner or operator of the
affected source. The boiler system(s) and any on-site energy use
system(s) accounting for at least 33 percent of the energy (e.g.,
steam, hot water, process heat, or electricity) production, as
applicable, will be evaluated to identify energy savings opportunities,
within the limit of performing a 24-hour on-site energy assessment.
(3) The energy assessment for facilities with affected boilers and
process heaters with a combined heat input capacity greater than 1.0
TBtu/year will be up to 24 on-site technical labor hours in length for
the first TBtu/yr plus 8 on-site technical labor hours for every
additional 1.0 TBtu/yr not to exceed 160 on-site technical hours, but
may be longer at the discretion of the owner or operator of the
affected source. The boiler system(s), process heater(s), and any on-
site energy use system(s) accounting for at least 20 percent of the
energy (e.g., steam, process heat, hot water, or electricity)
production, as applicable, will be evaluated to identify energy savings
opportunities.
(4) The on-site energy use systems serving as the basis for the
percent of affected boiler(s) and process heater(s) energy production
in paragraphs (1), (2), and (3) of this definition may be segmented by
production area or energy use area as most logical and applicable to
the specific facility being assessed (e.g., product X manufacturing
area; product Y drying area; Building Z).
* * * * *
Energy management program means a program that includes a set of
practices and procedures designed to manage energy use that are
demonstrated by the facility's energy policies, a facility energy
manager and other staffing responsibilities, energy performance
measurement and tracking methods, an energy saving goal, action plans,
operating procedures, internal reporting requirements, and periodic
review intervals used at the facility. Facilities may establish their
program through energy management systems compatible with ISO 50001.
Energy use system includes the following systems located on-site
that use energy (steam, hot water, or electricity) provided by the
affected boiler or process heater: process heating; compressed air
systems; machine drive (motors, pumps, fans); process cooling; facility
heating, ventilation, and air-conditioning systems; hot water systems;
building envelop; and lighting; or other systems that use steam, hot
water, process heat, or electricity provided by the affected boiler or
process heater. Energy use systems are only those systems using energy
clearly produced by affected boilers and process heaters.
Equivalent means the following only as this term is used in Table 6
to this subpart:
(1) An equivalent sample collection procedure means a published
voluntary consensus standard or practice (VCS) or EPA method that
includes collection of a minimum of three composite fuel samples, with
each composite
[[Page 7189]]
consisting of a minimum of three increments collected at approximately
equal intervals over the test period.
(2) An equivalent sample compositing procedure means a published
VCS or EPA method to systematically mix and obtain a representative
subsample (part) of the composite sample.
(3) An equivalent sample preparation procedure means a published
VCS or EPA method that: Clearly states that the standard, practice or
method is appropriate for the pollutant and the fuel matrix; or is
cited as an appropriate sample preparation standard, practice or method
for the pollutant in the chosen VCS or EPA determinative or analytical
method.
(4) An equivalent procedure for determining heat content means a
published VCS or EPA method to obtain gross calorific (or higher
heating) value.
(5) An equivalent procedure for determining fuel moisture content
means a published VCS or EPA method to obtain moisture content. If the
sample analysis plan calls for determining metals (especially the
mercury, selenium, or arsenic) using an aliquot of the dried sample,
then the drying temperature must be modified to prevent vaporizing
these metals. On the other hand, if metals analysis is done on an ``as
received'' basis, a separate aliquot can be dried to determine moisture
content and the metals concentration mathematically adjusted to a dry
basis.
(6) An equivalent pollutant (mercury, HCl) determinative or
analytical procedure means a published VCS or EPA method that clearly
states that the standard, practice, or method is appropriate for the
pollutant and the fuel matrix and has a published detection limit equal
or lower than the methods listed in Table 6 to this subpart for the
same purpose.
* * * * *
Federally enforceable means all limitations and conditions that are
enforceable by the EPA Administrator, including, but not limited to,
the requirements of 40 CFR parts 60, 61, 63, and 65, requirements
within any applicable state implementation plan, and any permit
requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and
40 CFR 51.24.
Fluidized bed boiler means a boiler utilizing a fluidized bed
combustion process that is not a pulverized coal boiler.
Fluidized bed boiler with an integrated fluidized bed heat
exchanger means a boiler utilizing a fluidized bed combustion where the
entire tube surface area is located outside of the furnace section at
the exit of the cyclone section and exposed to the flue gas stream for
conductive heat transfer. This design applies only to boilers in the
unit designed to burn coal/solid fossil fuel subcategory that fire coal
refuse.
* * * * *
Fuel cell means a boiler type in which the fuel is dropped onto
suspended fixed grates and is fired in a pile. The refractory-lined
fuel cell uses combustion air preheating and positioning of secondary
and tertiary air injection ports to improve boiler efficiency.
Fluidized bed, dutch oven, pile burner, hybrid suspension grate, and
suspension burners are not part of the fuel cell subcategory.
Fuel type means each category of fuels that share a common name or
classification. Examples include, but are not limited to, bituminous
coal, sub-bituminous coal, lignite, anthracite, biomass, distillate
oil, residual oil. Individual fuel types received from different
suppliers are not considered new fuel types.
Gaseous fuel includes, but is not limited to, natural gas, process
gas, landfill gas, coal derived gas, refinery gas, and biogas. Blast
furnace gas and process gases that are regulated under another subpart
of this part, or part 60, part 61, or part 65 of this chapter, are
exempted from this definition.
Heat input means heat derived from combustion of fuel in a boiler
or process heater and does not include the heat input from preheated
combustion air, recirculated flue gases, returned condensate, or
exhaust gases from other sources such as gas turbines, internal
combustion engines, kilns, etc.
Heavy liquid includes residual oil and any other liquid fuel not
classified as a light liquid.
* * * * *
Hot water heater means a closed vessel with a capacity of no more
than 120 U.S. gallons in which water is heated by combustion of
gaseous, liquid, or biomass/bio-based solid fuel and is withdrawn for
use external to the vessel. Hot water boilers (i.e., not generating
steam) combusting gaseous, liquid, or biomass fuel with a heat input
capacity of less than 1.6 million Btu per hour are included in this
definition. The 120 U.S. gallon capacity threshold to be considered a
hot water heater is independent of the 1.6 MMBtu/hr heat input capacity
threshold for hot water boilers. Hot water heater also means a tankless
unit that provides on demand hot water.
Hybrid suspension grate boiler means a boiler designed with air
distributors to spread the fuel material over the entire width and
depth of the boiler combustion zone. The biomass fuel combusted in
these units exceeds a moisture content of 40 percent on an as-fired
annual heat input basis. The drying and much of the combustion of the
fuel takes place in suspension, and the combustion is completed on the
grate or floor of the boiler. Fluidized bed, dutch oven, and pile
burner designs are not part of the hybrid suspension grate boiler
design category.
Industrial boiler means a boiler used in manufacturing, processing,
mining, and refining or any other industry to provide steam, hot water,
and/or electricity.
Light liquid includes distillate oil, biodiesel, or vegetable oil.
Limited-use boiler or process heater means any boiler or process
heater that burns any amount of solid, liquid, or gaseous fuels and has
a federally enforceable average annual capacity factor of no more than
10 percent.
Liquid fuel includes, but is not limited to, light liquid, heavy
liquid, any form of liquid fuel derived from petroleum, used oil,
liquid biofuels, biodiesel, vegetable oil, and comparable fuels as
defined under 40 CFR 261.38.
Load fraction means the actual heat input of a boiler or process
heater divided by heat input during the performance test that
established the minimum sorbent injection rate or minimum activated
carbon injection rate, expressed as a fraction (e.g., for 50 percent
load the load fraction is 0.5).
Major source for oil and natural gas production facilities, as used
in this subpart, shall have the same meaning as in Sec. 63.2, except
that:
(1) Emissions from any oil or gas exploration or production well
(with its associated equipment, as defined in this section), and
emissions from any pipeline compressor station or pump station shall
not be aggregated with emissions from other similar units to determine
whether such emission points or stations are major sources, even when
emission points are in a contiguous area or under common control;
(2) Emissions from processes, operations, or equipment that are not
part of the same facility, as defined in this section, shall not be
aggregated; and
(3) For facilities that are production field facilities, only HAP
emissions from glycol dehydration units and storage vessels with the
potential for flash emissions shall be aggregated for a major source
determination. For facilities that are not production field facilities,
HAP emissions from all HAP emission units shall be aggregated for a
major source determination.
[[Page 7190]]
Metal process furnaces are a subcategory of process heaters, as
defined in this subpart, which include natural gas-fired annealing
furnaces, preheat furnaces, reheat furnaces, aging furnaces, heat treat
furnaces, and homogenizing furnaces.
* * * * *
Minimum activated carbon injection rate means load fraction
multiplied by the lowest hourly average activated carbon injection rate
measured according to Table 7 to this subpart during the most recent
performance test demonstrating compliance with the applicable emission
limit.
Minimum oxygen level means the lowest hourly average oxygen level
measured according to Table 7 to this subpart during the most recent
performance test demonstrating compliance with the applicable emission
limit.
* * * * *
Minimum scrubber liquid flow rate means the lowest hourly average
liquid flow rate (e.g., to the PM scrubber or to the acid gas scrubber)
measured according to Table 7 to this subpart during the most recent
performance stack test demonstrating compliance with the applicable
emission limit.
* * * * *
Minimum sorbent injection rate means:
(1) The load fraction multiplied by the lowest hourly average
sorbent injection rate for each sorbent measured according to Table 7
to this subpart during the most recent performance test demonstrating
compliance with the applicable emission limits; or
(2) For fluidized bed combustion, the lowest average ratio of
sorbent to sulfur measured during the most recent performance test.
* * * * *
Natural gas means:
(1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon
gases found in geologic formations beneath the earth's surface, of
which the principal constituent is methane; or
(2) Liquefied petroleum gas, as defined in ASTM D1835 (incorporated
by reference, see Sec. 63.14); or
(3) A mixture of hydrocarbons that maintains a gaseous state at ISO
conditions. Additionally, natural gas must either be composed of at
least 70 percent methane by volume or have a gross calorific value
between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and
1,100 Btu per dry standard cubic foot); or
(4) Propane or propane derived synthetic natural gas. Propane means
a colorless gas derived from petroleum and natural gas, with the
molecular structure C3H8.
* * * * *
Other combustor means a unit designed to burn solid fuel that is
not classified as a dutch oven, fluidized bed, fuel cell, hybrid
suspension grate boiler, pulverized coal boiler, stoker, sloped grate,
or suspension boiler as defined in this subpart.
Other gas 1 fuel means a gaseous fuel that is not natural gas or
refinery gas and does not exceed a maximum concentration of 40
micrograms/cubic meters of mercury.
Oxygen analyzer system means all equipment required to determine
the oxygen content of a gas stream and used to monitor oxygen in the
boiler or process heater flue gas, boiler or process heater, firebox,
or other appropriate location. This definition includes oxygen trim
systems. The source owner or operator must install, calibrate,
maintain, and operate the oxygen analyzer system in accordance with the
manufacturer's recommendations.
Oxygen trim system means a system of monitors that is used to
maintain excess air at the desired level in a combustion device. A
typical system consists of a flue gas oxygen and/or CO monitor that
automatically provides a feedback signal to the combustion air
controller.
* * * * *
Period of gas curtailment or supply interruption means a period of
time during which the supply of gaseous fuel to an affected boiler or
process heater is restricted or halted for reasons beyond the control
of the facility. The act of entering into a contractual agreement with
a supplier of natural gas established for curtailment purposes does not
constitute a reason that is under the control of a facility for the
purposes of this definition. An increase in the cost or unit price of
natural gas due to normal market fluctuations not during periods of
supplier delivery restriction does not constitute a period of natural
gas curtailment or supply interruption. On-site gaseous fuel system
emergencies or equipment failures qualify as periods of supply
interruption when the emergency or failure is beyond the control of the
facility.
Pile burner means a boiler design incorporating a design where the
anticipated biomass fuel has a high relative moisture content. Grates
serve to support the fuel, and underfire air flowing up through the
grates provides oxygen for combustion, cools the grates, promotes
turbulence in the fuel bed, and fires the fuel. The most common form of
pile burning is the dutch oven.
Process heater means an enclosed device using controlled flame, and
the unit's primary purpose is to transfer heat indirectly to a process
material (liquid, gas, or solid) or to a heat transfer material (e.g.,
glycol or a mixture of glycol and water) for use in a process unit,
instead of generating steam. Process heaters are devices in which the
combustion gases do not come into direct contact with process
materials. A device combusting solid waste, as defined in Sec. 241.3
of this chapter, is not a process heater unless the device is exempt
from the definition of a solid waste incineration unit as provided in
section 129(g)(1) of the Clean Air Act. Process heaters do not include
units used for comfort heat or space heat, food preparation for on-site
consumption, or autoclaves. Waste heat process heaters are excluded
from this definition.
* * * * *
Qualified energy assessor means:
(1) Someone who has demonstrated capabilities to evaluate energy
savings opportunities for steam generation and major energy using
systems, including, but not limited to:
(i) Boiler combustion management.
(ii) Boiler thermal energy recovery, including
(A) Conventional feed water economizer,
(B) Conventional combustion air preheater, and
(C) Condensing economizer.
(iii) Boiler blowdown thermal energy recovery.
(iv) Primary energy resource selection, including
(A) Fuel (primary energy source) switching, and
(B) Applied steam energy versus direct-fired energy versus
electricity.
(v) Insulation issues.
(vi) Steam trap and steam leak management.
(vi) Condensate recovery.
(viii) Steam end-use management.
(2) Capabilities and knowledge includes, but is not limited to:
(i) Background, experience, and recognized abilities to perform the
assessment activities, data analysis, and report preparation.
(ii) Familiarity with operating and maintenance practices for steam
or process heating systems.
(iii) Additional potential steam system improvement opportunities
including improving steam turbine operations and reducing steam demand.
(iv) Additional process heating system opportunities including
effective utilization of waste heat and use of proper process heating
methods.
(v) Boiler-steam turbine cogeneration systems.
[[Page 7191]]
(vi) Industry specific steam end-use systems.
* * * * *
Regulated gas stream means an offgas stream that is routed to a
boiler or process heater for the purpose of achieving compliance with a
standard under another subpart of this part or part 60, part 61, or
part 65 of this chapter.
Residential boiler means a boiler used to provide heat and/or hot
water and/or as part of a residential combined heat and power system.
This definition includes boilers located at an institutional facility
(e.g., university campus, military base, church grounds) or commercial/
industrial facility (e.g., farm) used primarily to provide heat and/or
hot water for:
(1) A dwelling containing four or fewer families; or
(2) A single unit residence dwelling that has since been converted
or subdivided into condominiums or apartments.
Residual oil means crude oil, fuel oil that does not comply with
the specifications under the definition of distillate oil, and all fuel
oil numbers 4, 5, and 6, as defined by the American Society of Testing
and Materials in ASTM D396-10 (incorporated by reference, see Sec.
63.14(b)).
* * * * *
Secondary material means the material as defined in Sec. 241.2 of
this chapter.
Shutdown means the cessation of operation of a boiler or process
heater for any purpose. Shutdown begins either when none of the steam
from the boiler is supplied for heating and/or producing electricity,
or for any other purpose, or at the point of no fuel being fired in the
boiler or process heater, whichever is earlier. Shutdown ends when
there is no steam and no heat being supplied and no fuel being fired in
the boiler or process heater.
Sloped grate means a unit where the solid fuel is fed to the top of
the grate from where it slides downwards; while sliding the fuel first
dries and then ignites and burns. The ash is deposited at the bottom of
the grate. Fluidized bed, dutch oven, pile burner, hybrid suspension
grate, suspension burners, and fuel cells are not considered to be a
sloped grate design.
Solid fossil fuel includes, but is not limited to, coal, coke,
petroleum coke, and tire derived fuel.
* * * * *
Startup means either the first-ever firing of fuel in a boiler or
process heater for the purpose of supplying steam or heat for heating
and/or producing electricity, or for any other purpose, or the firing
of fuel in a boiler after a shutdown event for any purpose. Startup
ends when any of the steam or heat from the boiler or process heater is
supplied for heating, and/or producing electricity, or for any other
purpose.
Steam output means:
(1) For a boiler that produces steam for process or heating only
(no power generation), the energy content in terms of MMBtu of the
boiler steam output,
(2) For a boiler that cogenerates process steam and electricity
(also known as combined heat and power), the total energy output, which
is the sum of the energy content of the steam exiting the turbine and
sent to process in MMBtu and the energy of the electricity generated
converted to MMBtu at a rate of 10,000 Btu per kilowatt-hour generated
(10 MMBtu per megawatt-hour), and
(3) For a boiler that generates only electricity, the alternate
output-based emission limits would be calculated using Equations 21
through 25 of this section, as appropriate:
(i) For emission limits for boilers in the unit designed to burn
solid fuel subcategory use Equation 21 of this section:
[GRAPHIC] [TIFF OMITTED] TR31JA13.025
Where:
ELOBE = Emission limit in units of pounds per megawatt-
hour.
ELT = Appropriate emission limit from Table 1 or 2 of
this subpart in units of pounds per million Btu heat input.
(ii) For PM and CO emission limits for boilers in one of the
subcategories of units designed to burn coal use Equation 22 of this
section:
[GRAPHIC] [TIFF OMITTED] TR31JA13.026
Where:
ELOBE = Emission limit in units of pounds per megawatt-
hour.
ELT = Appropriate emission limit from Table 1 or 2 of
this subpart in units of pounds per million Btu heat input.
(iii) For PM and CO emission limits for boilers in one of the
subcategories of units designed to burn biomass use Equation 23 of this
section:
[GRAPHIC] [TIFF OMITTED] TR31JA13.027
Where:
ELOBE = Emission limit in units of pounds per megawatt-
hour.
ELT = Appropriate emission limit from Table 1 or 2 of
this subpart in units of pounds per million Btu heat input.
(iv) For emission limits for boilers in one of the subcategories of
units designed to burn liquid fuels use Equation 24 of this section:
[GRAPHIC] [TIFF OMITTED] TR31JA13.028
Where:
ELOBE = Emission limit in units of pounds per megawatt-
hour.
ELT = Appropriate emission limit from Table 1 or 2 of
this subpart in units of pounds per million Btu heat input.
(v) For emission limits for boilers in the unit designed to burn
gas 2 (other)
[[Page 7192]]
subcategory, use Equation 25 of this section:
[GRAPHIC] [TIFF OMITTED] TR31JA13.029
Where:
ELOBE = Emission limit in units of pounds per megawatt-
hour.
ELT = Appropriate emission limit from Table 1 or 2 of
this subpart in units of pounds per million Btu heat input.
Stoker means a unit consisting of a mechanically operated fuel
feeding mechanism, a stationary or moving grate to support the burning
of fuel and admit under-grate air to the fuel, an overfire air system
to complete combustion, and an ash discharge system. This definition of
stoker includes air swept stokers. There are two general types of
stokers: Underfeed and overfeed. Overfeed stokers include mass feed and
spreader stokers. Fluidized bed, dutch oven, pile burner, hybrid
suspension grate, suspension burners, and fuel cells are not considered
to be a stoker design.
Stoker/sloped grate/other unit designed to burn kiln dried biomass
means the unit is in the units designed to burn biomass/bio-based solid
subcategory that is either a stoker, sloped grate, or other combustor
design and is not in the stoker/sloped grate/other units designed to
burn wet biomass subcategory.
Stoker/sloped grate/other unit designed to burn wet biomass means
the unit is in the units designed to burn biomass/bio-based solid
subcategory that is either a stoker, sloped grate, or other combustor
design and any of the biomass/bio-based solid fuel combusted in the
unit exceeds 20 percent moisture on an annual heat input basis.
Suspension burner means a unit designed to fire dry biomass/
biobased solid particles in suspension that are conveyed in an
airstream to the furnace like pulverized coal. The combustion of the
fuel material is completed on a grate or floor below. The biomass/
biobased fuel combusted in the unit shall not exceed 20 percent
moisture on an annual heat input basis. Fluidized bed, dutch oven, pile
burner, and hybrid suspension grate units are not part of the
suspension burner subcategory.
Temporary boiler means any gaseous or liquid fuel boiler that is
designed to, and is capable of, being carried or moved from one
location to another by means of, for example, wheels, skids, carrying
handles, dollies, trailers, or platforms. A boiler is not a temporary
boiler if any one of the following conditions exists:
(1) The equipment is attached to a foundation.
(2) The boiler or a replacement remains at a location within the
facility and performs the same or similar function for more than 12
consecutive months, unless the regulatory agency approves an extension.
An extension may be granted by the regulating agency upon petition by
the owner or operator of a unit specifying the basis for such a
request. Any temporary boiler that replaces a temporary boiler at a
location and performs the same or similar function will be included in
calculating the consecutive time period.
(3) The equipment is located at a seasonal facility and operates
during the full annual operating period of the seasonal facility,
remains at the facility for at least 2 years, and operates at that
facility for at least 3 months each year.
(4) The equipment is moved from one location to another within the
facility but continues to perform the same or similar function and
serve the same electricity, steam, and/or hot water system in an
attempt to circumvent the residence time requirements of this
definition.
Total selected metals (TSM) means the sum of the following metallic
hazardous air pollutants: arsenic, beryllium, cadmium, chromium, lead,
manganese, nickel and selenium.
Traditional fuel means the fuel as defined in Sec. 241.2 of this
chapter.
Tune-up means adjustments made to a boiler or process heater in
accordance with the procedures outlined in Sec. 63.7540(a)(10).
* * * * *
Ultra low sulfur liquid fuel means a distillate oil that has less
than or equal to 15 ppm sulfur.
* * * * *
Unit designed to burn gas 1 subcategory includes any boiler or
process heater that burns only natural gas, refinery gas, and/or other
gas 1 fuels. Gaseous fuel boilers and process heaters that burn liquid
fuel for periodic testing of liquid fuel, maintenance, or operator
training, not to exceed a combined total of 48 hours during any
calendar year, are included in this definition. Gaseous fuel boilers
and process heaters that burn liquid fuel during periods of gas
curtailment or gas supply interruptions of any duration are also
included in this definition.
Unit designed to burn gas 2 (other) subcategory includes any boiler
or process heater that is not in the unit designed to burn gas 1
subcategory and burns any gaseous fuels either alone or in combination
with less than 10 percent coal/solid fossil fuel, and less than 10
percent biomass/bio-based solid fuel on an annual heat input basis, and
no liquid fuels. Gaseous fuel boilers and process heaters that are not
in the unit designed to burn gas 1 subcategory and that burn liquid
fuel for periodic testing of liquid fuel, maintenance, or operator
training, not to exceed a combined total of 48 hours during any
calendar year, are included in this definition. Gaseous fuel boilers
and process heaters that are not in the unit designed to burn gas 1
subcategory and that burn liquid fuel during periods of gas curtailment
or gas supply interruption of any duration are also included in this
definition.
Unit designed to burn heavy liquid subcategory means a unit in the
unit designed to burn liquid subcategory where at least 10 percent of
the heat input from liquid fuels on an annual heat input basis comes
from heavy liquids.
Unit designed to burn light liquid subcategory means a unit in the
unit designed to burn liquid subcategory that is not part of the unit
designed to burn heavy liquid subcategory.
Unit designed to burn liquid subcategory includes any boiler or
process heater that burns any liquid fuel, but less than 10 percent
coal/solid fossil fuel and less than 10 percent biomass/bio-based solid
fuel on an annual heat input basis, either alone or in combination with
gaseous fuels. Units in the unit design to burn gas 1 or unit designed
to burn gas 2 (other) subcategories that burn liquid fuel for periodic
testing of liquid fuel, maintenance, or operator training, not to
exceed a combined total of 48 hours during any calendar year are not
included in this definition. Units in the unit design to burn gas 1 or
unit designed to burn gas 2 (other) subcategories during periods of gas
curtailment or gas supply interruption of any duration are also not
included in this definition.
Unit designed to burn liquid fuel that is a non-continental unit
means an industrial, commercial, or institutional boiler or process
heater meeting the definition of the unit designed to burn
[[Page 7193]]
liquid subcategory located in the State of Hawaii, the Virgin Islands,
Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern
Mariana Islands.
Unit designed to burn solid fuel subcategory means any boiler or
process heater that burns only solid fuels or at least 10 percent solid
fuel on an annual heat input basis in combination with liquid fuels or
gaseous fuels.
Vegetable oil means oils extracted from vegetation.
* * * * *
Waste heat boiler means a device that recovers normally unused
energy (i.e., hot exhaust gas) and converts it to usable heat. Waste
heat boilers are also referred to as heat recovery steam generators.
Waste heat boilers are heat exchangers generating steam from incoming
hot exhaust gas from an industrial (e.g., thermal oxidizer, kiln,
furnace) or power (e.g., combustion turbine, engine) equipment. Duct
burners are sometimes used to increase the temperature of the incoming
hot exhaust gas.
Waste heat process heater means an enclosed device that recovers
normally unused energy (i.e., hot exhaust gas) and converts it to
usable heat. Waste heat process heaters are also referred to as
recuperative process heaters. This definition includes both fired and
unfired waste heat process heaters.
* * * * *
0
28. Table 1 to subpart DDDDD of part 63 is revised to read as follows:
As stated in Sec. 63.7500, you must comply with the following
applicable emission limits:
Table 1 to Subpart DDDDD of Part 63--Emission Limits for New or Reconstructed Boilers and Process Heaters
[Units with heat input capacity of 10 million Btu per hour or greater]
----------------------------------------------------------------------------------------------------------------
Or the emissions
The emissions must must not exceed
not exceed the the following Using this
If your boiler or process heater For the following following emission alternative output- specified sampling
is in this subcategory . . . pollutants . . . limits, except based limits, volume or test run
during startup and except during duration . . .
shutdown . . . startup and
shutdown . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories a. HCl............ 2.2E-02 lb per 2.5E-02 lb per For M26A, collect
designed to burn solid fuel. MMBtu of heat MMBtu of steam a minimum of 1
input. output or 0.28 lb dscm per run; for
per MWh. M26 collect a
minimum of 120
liters per run.
b. Mercury........ 8.0E-07 \a\ lb per 8.7E-07 \a\ lb per For M29, collect a
MMBtu of heat MMBtu of steam minimum of 4 dscm
input. output or 1.1E-05 per run; for M30A
\a\ lb per MWh. or M30B, collect
a minimum sample
as specified in
the method; for
ASTM D6784 \b\
collect a minimum
of 4 dscm.
2. Units designed to burn coal/ a. Filterable PM 1.1E-03 lb per 1.1E-03 lb per Collect a minimum
solid fossil fuel. (or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (2.3E- output or 1.4E-02 run.
05 lb per MMBtu lb per MWh; or
of heat input). (2.7E-05 lb per
MMBtu of steam
output or 2.9E-04
lb per MWh).
3. Pulverized coal boilers a. Carbon monoxide 130 ppm by volume 0.11 lb per MMBtu 1 hr minimum
designed to burn coal/solid (CO) (or CEMS). on a dry basis of steam output sampling time.
fossil fuel. corrected to 3 or 1.4 lb per
percent oxygen, 3- MWh; 3-run
run average; or average.
(320 ppm by
volume on a dry
basis corrected
to 3 percent
oxygen, 30-day
rolling average).
4. Stokers designed to burn coal/ a. CO (or CEMS)... 130 ppm by volume 0.12 lb per MMBtu 1 hr minimum
solid fossil fuel. on a dry basis of steam output sampling time.
corrected to 3 or 1.4 lb per
percent oxygen, 3- MWh; 3-run
run average; or average.
(340 ppm by
volume on a dry
basis corrected
to 3 percent
oxygen, 30-day
rolling average).
5. Fluidized bed units designed a. CO (or CEMS)... 130 ppm by volume 0.11 lb per MMBtu 1 hr minimum
to burn coal/solid fossil fuel. on a dry basis of steam output sampling time.
corrected to 3 or 1.4 lb per
percent oxygen, 3- MWh; 3-run
run average; or average.
(230 ppm by
volume on a dry
basis corrected
to 3 percent
oxygen, 30-day
rolling average).
6. Fluidized bed units with an a. CO (or CEMS)... 140 ppm by volume 1.2E-01 lb per 1 hr minimum
integrated heat exchanger on a dry basis MMBtu of steam sampling time.
designed to burn coal/solid corrected to 3 output or 1.5 lb
fossil fuel. percent oxygen, 3- per MWh; 3-run
run average; or average.
(150 ppm by
volume on a dry
basis corrected
to 3 percent
oxygen, 30-day
rolling average).
7. Stokers/sloped grate/others a. CO (or CEMS)... 620 ppm by volume 5.8E-01 lb per 1 hr minimum
designed to burn wet biomass on a dry basis MMBtu of steam sampling time.
fuel. corrected to 3 output or 6.8 lb
percent oxygen, 3- per MWh; 3-run
run average; or average.
(390 ppm by
volume on a dry
basis corrected
to 3 percent
oxygen, 30-day
rolling average).
b. Filterable PM 3.0E-02 lb per 3.5E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (2.6E- output or 4.2E-01 run.
05 lb per MMBtu lb per MWh; or
of heat input). (2.7E-05 lb per
MMBtu of steam
output or 3.7E-04
lb per MWh).
[[Page 7194]]
8. Stokers/sloped grate/others a. CO............. 460 ppm by volume 4.2E-01 lb per 1 hr minimum
designed to burn kiln-dried on a dry basis MMBtu of steam sampling time.
biomass fuel. corrected to 3 output or 5.1 lb
percent oxygen. per MWh.
b. Filterable PM 3.0E-02 lb per 3.5E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (4.0E- output or 4.2E-01 run.
03 lb per MMBtu lb per MWh; or
of heat input). (4.2E-03 lb per
MMBtu of steam
output or 5.6E-02
lb per MWh).
9. Fluidized bed units designed a. CO (or CEMS)... 230 ppm by volume 2.2E-01 lb per 1 hr minimum
to burn biomass/bio-based on a dry basis MMBtu of steam sampling time.
solids. corrected to 3 output or 2.6 lb
percent oxygen, 3- per MWh; 3-run
run average; or average.
(310 ppm by
volume on a dry
basis corrected
to 3 percent
oxygen, 30-day
rolling average).
b. Filterable PM 9.8E-03 lb per 1.2E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (8.3E- output or 0.14 lb run.
05 \a\ lb per per MWh; or (1.1E-
MMBtu of heat 04 \a\ lb per
input). MMBtu of steam
output or 1.2E-03
\a\ lb per MWh).
10. Suspension burners designed a. CO (or CEMS)... 2,400 ppm by 1.9 lb per MMBtu 1 hr minimum
to burn biomass/bio-based volume on a dry of steam output sampling time.
solids. basis corrected or 27 lb per MWh;
to 3 percent 3-run average.
oxygen, 3-run
average; or
(2,000 ppm by
volume on a dry
basis corrected
to 3 percent
oxygen, 10-day
rolling average).
b. Filterable PM 3.0E-02 lb per 3.1E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (6.5E- output or 4.2E-01 run.
03 lb per MMBtu lb per MWh; or
of heat input). (6.6E-03 lb per
MMBtu of steam
output or 9.1E-02
lb per MWh).
11. Dutch Ovens/Pile burners a. CO (or CEMS)... 330 ppm by volume 3.5E-01 lb per 1 hr minimum
designed to burn biomass/bio- on a dry basis MMBtu of steam sampling time.
based solids. corrected to 3 output or 3.6 lb
percent oxygen, 3- per MWh; 3-run
run average; or average.
(520 ppm by
volume on a dry
basis corrected
to 3 percent
oxygen, 10-day
rolling average).
b. Filterable PM 3.2E-03 lb per 4.3E-03 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (3.9E- output or 4.5E-02 run.
05 lb per MMBtu lb per MWh; or
of heat input). (5.2E-05 lb per
MMBtu of steam
output or 5.5E-04
lb per MWh).
12. Fuel cell units designed to a. CO............. 910 ppm by volume 1.1 lb per MMBtu 1 hr minimum
burn biomass/bio-based solids. on a dry basis of steam output sampling time.
corrected to 3 or 1.0E+01 lb per
percent oxygen. MWh.
b. Filterable PM 2.0E-02 lb per 3.0E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (2.9E- output or 2.8E-01 run.
05 \a\ lb per lb per MWh; or
MMBtu of heat (5.1E-05 lb per
input). MMBtu of steam
output or 4.1E-04
lb per MWh).
13. Hybrid suspension grate a. CO (or CEMS)... 1,100 ppm by 1.4 lb per MMBtu 1 hr minimum
boiler designed to burn biomass/ volume on a dry of steam output sampling time.
bio-based solids. basis corrected or 12 lb per MWh;
to 3 percent 3-run average.
oxygen, 3-run
average; or (900
ppm by volume on
a dry basis
corrected to 3
percent oxygen,
30-day rolling
average).
b. Filterable PM 2.6E-02 lb per 3.3E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (4.4E- output or 3.7E-01 run.
04 lb per MMBtu lb per MWh; or
of heat input). (5.5E-04 lb per
MMBtu of steam
output or 6.2E-03
lb per MWh).
14. Units designed to burn a. HCl............ 4.4E-04 lb per 4.8E-04 lb per For M26A: Collect
liquid fuel. MMBtu of heat MMBtu of steam a minimum of 2
input. output or 6.1E-03 dscm per run; for
lb per MWh. M26, collect a
minimum of 240
liters per run.
b. Mercury........ 4.8E-07 \a\ lb per 5.3E-07 \a\ lb per For M29, collect a
MMBtu of heat MMBtu of steam minimum of 4 dscm
input. output or 6.7E-06 per run; for M30A
\a\ lb per MWh. or M30B, collect
a minimum sample
as specified in
the method; for
ASTM D6784 \b\
collect a minimum
of 4 dscm.
[[Page 7195]]
15. Units designed to burn heavy a. CO............. 130 ppm by volume 0.13 lb per MMBtu 1 hr minimum
liquid fuel. on a dry basis of steam output sampling time.
corrected to 3 or 1.4 lb per
percent oxygen, 3- MWh; 3-run
run average. average.
b. Filterable PM 1.3E-02 lb per 1.5E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (7.5E- output or 1.8E-01 run.
05 lb per MMBtu lb per MWh; or
of heat input). (8.2E-05 lb per
MMBtu of steam
output or 1.1E-03
lb per MWh).
16. Units designed to burn light a. CO............. 130 ppm by volume 0.13 lb per MMBtu 1 hr minimum
liquid fuel. on a dry basis of steam output sampling time.
corrected to 3 or 1.4 lb per MWh.
percent oxygen.
b. Filterable PM 1.1E-03 \a\ lb per 1.2E-03 \a\ lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (2.9E- output or 1.6E-02 run.
05 lb per MMBtu \a\ lb per MWh;
of heat input). or (3.2E-05 lb
per MMBtu of
steam output or
4.0E-04 lb per
MWh).
17. Units designed to burn a. CO............. 130 ppm by volume 0.13 lb per MMBtu 1 hr minimum
liquid fuel that are non- on a dry basis of steam output sampling time.
continental units. corrected to 3 or 1.4 lb per
percent oxygen, 3- MWh; 3-run
run average based average.
on stack test.
b. Filterable PM 2.3E-02 lb per 2.5E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 4 dscm per
input; or (8.6E- output or 3.2E-01 run.
04 lb per MMBtu lb per MWh; or
of heat input). (9.4E-04 lb per
MMBtu of steam
output or 1.2E-02
lb per MWh).
18. Units designed to burn gas 2 a. CO............. 130 ppm by volume 0.16 lb per MMBtu 1 hr minimum
(other) gases. on a dry basis of steam output sampling time.
corrected to 3 or 1.0 lb per MWh.
percent oxygen.
b. HCl............ 1.7E-03 lb per 2.9E-03 lb per For M26A, Collect
MMBtu of heat MMBtu of steam a minimum of 2
input. output or 1.8E-02 dscm per run; for
lb per MWh. M26, collect a
minimum of 240
liters per run.
c. Mercury........ 7.9E-06 lb per 1.4E-05 lb per For M29, collect a
MMBtu of heat MMBtu of steam minimum of 3 dscm
input. output or 8.3E-05 per run; for M30A
lb per MWh. or M30B, collect
a minimum sample
as specified in
the method; for
ASTM D6784 \b\
collect a minimum
of 3 dscm.
d. Filterable PM 6.7E-03 lb per 1.2E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (2.1E- output or 7.0E-02 run.
04 lb per MMBtu lb per MWh; or
of heat input). (3.5E-04 lb per
MMBtu of steam
output or 2.2E-03
lb per MWh).
----------------------------------------------------------------------------------------------------------------
\a\ If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant
for at least 2 consecutive years show that your emissions are at or below this limit, you can skip testing
according to Sec. 63.7515 if all of the other provisions of Sec. 63.7515 are met. For all other pollutants
that do not contain a footnote ``a'', your performance tests for this pollutant for at least 2 consecutive
years must show that your emissions are at or below 75 percent of this limit in order to qualify for skip
testing.
\b\ Incorporated by reference, see Sec. 63.14.
\c\ If your affected source is a new or reconstructed affected source that commenced construction or
reconstruction after June 4, 2010, and before January 31, 2013, you may comply with the emission limits in
Tables 11, 12 or 13 to this subpart until January 31, 2016. On and after January 31, 2016, you must comply
with the emission limits in Table 1 to this subpart.
0
29. Table 2 to subpart DDDDD of part 63 is revised to read as follows:
As stated in Sec. 63.7500, you must comply with the following
applicable emission limits:
Table 2 to Subpart DDDDD of Part 63--Emission Limits for Existing Boilers and Process Heaters
[Units with heat input capacity of 10 million Btu per hour or greater]
----------------------------------------------------------------------------------------------------------------
The emissions must
The emissions must not exceed the
not exceed the following Using this
If your boiler or process heater For the following following emission alternative output- specified sampling
is in this subcategory . . . pollutants . . . limits, except based limits, volume or test run
during startup and except during duration . . .
shutdown . . . startup and
shutdown . . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories a. HCl............ 2.2E-02 lb per 2.5E-02 lb per For M26A, Collect
designed to burn solid fuel. MMBtu of heat MMBtu of steam a minimum of 1
input. output or 0.27 lb dscm per run; for
per MWh. M26, collect a
minimum of 120
liters per run.
[[Page 7196]]
b. Mercury........ 5.7E-06 lb per 6.4E-06 lb per For M29, collect a
MMBtu of heat MMBtu of steam minimum of 3 dscm
input. output or 7.3E-05 per run; for M30A
lb per MWh. or M30B, collect
a minimum sample
as specified in
the method; for
ASTM D6784 \b\
collect a minimum
of 3 dscm.
2. Units design to burn coal/ a. Filterable PM 4.0E-02 lb per 4.2E-02 lb per Collect a minimum
solid fossil fuel. (or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (5.3E- output or 4.9E-01 run.
05 lb per MMBtu lb per MWh; or
of heat input). (5.6E-05 lb per
MMBtu of steam
output or 6.5E-04
lb per MWh).
3. Pulverized coal boilers a. CO (or CEMS)... 130 ppm by volume 0.11 lb per MMBtu 1 hr minimum
designed to burn coal/solid on a dry basis of steam output sampling time.
fossil fuel. corrected to 3 or 1.4 lb per
percent oxygen, 3- MWh; 3-run
run average; or average.
(320 ppm by
volume on a dry
basis corrected
to 3 percent
oxygen, 30-day
rolling average).
4. Stokers designed to burn coal/ a. CO (or CEMS)... 160 ppm by volume 0.14 lb per MMBtu 1 hr minimum
solid fossil fuel. on a dry basis of steam output sampling time.
corrected to 3 or 1.7 lb per
percent oxygen, 3- MWh; 3-run
run average; or average.
(340 ppm by
volume on a dry
basis corrected
to 3 percent
oxygen, 30-day
rolling average).
5. Fluidized bed units designed a. CO (or CEMS)... 130 ppm by volume 0.12 lb per MMBtu 1 hr minimum
to burn coal/solid fossil fuel. on a dry basis of steam output sampling time.
corrected to 3 or 1.4 lb per
percent oxygen, 3- MWh; 3-run
run average; or average.
(230 ppm by
volume on a dry
basis corrected
to 3 percent
oxygen, 30-day
rolling average).
6. Fluidized bed units with an a. CO (or CEMS)... 140 ppm by volume 1.3E-01 lb per 1 hr minimum
integrated heat exchanger on a dry basis MMBtu of steam sampling time.
designed to burn coal/solid corrected to 3 output or 1.5 lb
fossil fuel. percent oxygen, 3- per MWh; 3-run
run average; or average.
(150 ppm by
volume on a dry
basis corrected
to 3 percent
oxygen, 30-day
rolling average).
7. Stokers/sloped grate/others a. CO (or CEMS)... 1,500 ppm by 1.4 lb per MMBtu 1 hr minimum
designed to burn wet biomass volume on a dry of steam output sampling time.
fuel. basis corrected or 17 lb per MWh;
to 3 percent 3-run average.
oxygen, 3-run
average; or (720
ppm by volume on
a dry basis
corrected to 3
percent oxygen,
30-day rolling
average).
b. Filterable PM 3.7E-02 lb per 4.3E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (2.4E- output or 5.2E-01 run.
04 lb per MMBtu lb per MWh; or
of heat input). (2.8E-04 lb per
MMBtu of steam
output or 3.4E-04
lb per MWh).
8. Stokers/sloped grate/others a. CO............. 460 ppm by volume 4.2E-01 lb per 1 hr minimum
designed to burn kiln-dried on a dry basis MMBtu of steam sampling time.
biomass fuel. corrected to 3 output or 5.1 lb
percent oxygen. per MWh.
b. Filterable PM 3.2E-01 lb per 3.7E-01 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 1 dscm per
input; or (4.0E- output or 4.5 lb run.
03 lb per MMBtu per MWh; or (4.6E-
of heat input). 03 lb per MMBtu
of steam output
or 5.6E-02 lb per
MWh).
9. Fluidized bed units designed a. CO (or CEMS)... 470 ppm by volume 4.6E-01 lb per 1 hr minimum
to burn biomass/bio-based solid. on a dry basis MMBtu of steam sampling time.
corrected to 3 output or 5.2 lb
percent oxygen, 3- per MWh; 3-run
run average; or average.
(310 ppm by
volume on a dry
basis corrected
to 3 percent
oxygen, 30-day
rolling average).
b. Filterable PM 1.1E-01 lb per 1.4E-01 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 1 dscm per
input; or (1.2E- output or 1.6 lb run.
03 lb per MMBtu per MWh; or (1.5E-
of heat input). 03 lb per MMBtu
of steam output
or 1.7E-02 lb per
MWh).
[[Page 7197]]
10. Suspension burners designed a. CO (or CEMS)... 2,400 ppm by 1.9 lb per MMBtu 1 hr minimum
to burn biomass/bio-based solid. volume on a dry of steam output sampling time.
basis corrected or 27 lb per MWh;
to 3 percent 3-run average.
oxygen, 3-run
average; or
(2,000 ppm by
volume on a dry
basis corrected
to 3 percent
oxygen, 10-day
rolling average).
b. Filterable PM 5.1E-02 lb per 5.2E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (6.5E- output or 7.1E-01 run.
03 lb per MMBtu lb per MWh; or
of heat input). (6.6E-03 lb per
MMBtu of steam
output or 9.1E-02
lb per MWh).
11. Dutch Ovens/Pile burners a. CO (or CEMS)... 770 ppm by volume 8.4E-01 lb per 1 hr minimum
designed to burn biomass/bio- on a dry basis MMBtu of steam sampling time.
based solid. corrected to 3 output or 8.4 lb
percent oxygen, 3- per MWh; 3-run
run average; or average.
(520 ppm by
volume on a dry
basis corrected
to 3 percent
oxygen, 10-day
rolling average).
b. Filterable PM 2.8E-01 lb per 3.9E-01 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 1 dscm per
input; or (2.0E- output or 3.9 lb run.
03 lb per MMBtu per MWh; or (2.8E-
of heat input). 03 lb per MMBtu
of steam output
or 2.8E-02 lb per
MWh).
12. Fuel cell units designed to a. CO............. 1,100 ppm by 2.4 lb per MMBtu 1 hr minimum
burn biomass/bio-based solid. volume on a dry of steam output sampling time.
basis corrected or 12 lb per MWh.
to 3 percent
oxygen.
b. Filterable PM 2.0E-02 lb per 5.5E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (5.8E- output or 2.8E-01 run.
03 lb per MMBtu lb per MWh; or
of heat input). (1.6E-02 lb per
MMBtu of steam
output or 8.1E-02
lb per MWh).
13. Hybrid suspension grate a. CO (or CEMS)... 2,800 ppm by 2.8 lb per MMBtu 1 hr minimum
units designed to burn biomass/ volume on a dry of steam output sampling time.
bio-based solid. basis corrected or 31 lb per MWh;
to 3 percent 3-run average.
oxygen, 3-run
average; or (900
ppm by volume on
a dry basis
corrected to 3
percent oxygen,
30-day rolling
average).
b. Filterable PM 4.4E-01 lb per 5.5E-01 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 1 dscm per
input; or (4.5E- output or 6.2 lb run.
04 lb per MMBtu per MWh; or (5.7E-
of heat input). 04 lb per MMBtu
of steam output
or 6.3E-03 lb per
MWh).
14. Units designed to burn a. HCl............ 1.1E-03 lb per 1.4E-03 lb per For M26A, collect
liquid fuel. MMBtu of heat MMBtu of steam a minimum of 2
input. output or 1.6E-02 dscm per run; for
lb per MWh. M26, collect a
minimum of 240
liters per run.
b. Mercury........ 2.0E-06 lb per 2.5E-06 lb per For M29, collect a
MMBtu of heat MMBtu of steam minimum of 3 dscm
input. output or 2.8E-05 per run; for M30A
lb per MWh. or M30B collect a
minimum sample as
specified in the
method, for ASTM
D6784 \b\ collect
a minimum of 2
dscm.
15. Units designed to burn heavy a. CO............. 130 ppm by volume 0.13 lb per MMBtu 1 hr minimum
liquid fuel. on a dry basis of steam output sampling time.
corrected to 3 or 1.4 lb per
percent oxygen, 3- MWh; 3-run
run average. average.
b. Filterable PM 6.2E-02 lb per 7.5E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 1 dscm per
input; or (2.0E- output or 8.6E-01 run.
04 lb per MMBtu lb per MWh; or
of heat input). (2.5E-04 lb per
MMBtu of steam
output or 2.8E-03
lb per MWh).
16. Units designed to burn light a. CO............. 130 ppm by volume 0.13 lb per MMBtu 1 hr minimum
liquid fuel. on a dry basis of steam output sampling time.
corrected to 3 or 1.4 lb per MWh.
percent oxygen.
b. Filterable PM 7.9E-03 lb per 9.6E-03 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input; or (6.2E- output or 1.1E-01 run.
05 lb per MMBtu lb per MWh; or
of heat input). (7.5E-05 lb per
MMBtu of steam
output or 8.6E-04
lb per MWh).
17. Units designed to burn a. CO............. 130 ppm by volume 0.13 lb per MMBtu 1 hr minimum
liquid fuel that are non- on a dry basis of steam output sampling time.
continental units. corrected to 3 or 1.4 lb per
percent oxygen, 3- MWh; 3-run
run average based average.
on stack test.
[[Page 7198]]
b. Filterable PM 2.7E-01 lb per 3.3E-01 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 2 dscm per
input; or (8.6E- output or 3.8 lb run.
04 lb per MMBtu per MWh; or (1.1E-
of heat input). 03 lb per MMBtu
of steam output
or 1.2E-02 lb per
MWh).
18. Units designed to burn gas 2 a. CO............. 130 ppm by volume 0.16 lb per MMBtu 1 hr minimum
(other) gases. on a dry basis of steam output sampling time.
corrected to 3 or 1.0 lb per MWh.
percent oxygen.
b. HCl............ 1.7E-03 lb per 2.9E-03 lb per For M26A, collect
MMBtu of heat MMBtu of steam a minimum of 2
input. output or 1.8E-02 dscm per run; for
lb per MWh. M26, collect a
minimum of 240
liters per run.
c. Mercury........ 7.9E-06 lb per 1.4E-05 lb per For M29, collect a
MMBtu of heat MMBtu of steam minimum of 3 dscm
input. output or 8.3E-05 per run; for M30A
lb per MWh. or M30B, collect
a minimum sample
as specified in
the method; for
ASTM D6784 \b\
collect a minimum
of 2 dscm.
d. Filterable PM 6.7E-03 lb per 1.2E-02 lb per Collect a minimum
(or TSM). MMBtu of heat MMBtu of steam of 3 dscm per
input or (2.1E-04 output or 7.0E-02 run.
lb per MMBtu of lb per MWh; or
heat input). (3.5E-04 lb per
MMBtu of steam
output or 2.2E-03
lb per MWh).
----------------------------------------------------------------------------------------------------------------
\a\ If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant
for at least 2 consecutive years show that your emissions are at or below this limit, you can skip testing
according to Sec. 63.7515 if all of the other provisions of Sec. 63.7515 are met. For all other pollutants
that do not contain a footnote a, your performance tests for this pollutant for at least 2 consecutive years
must show that your emissions are at or below 75 percent of this limit in order to qualify for skip testing.
\b\ Incorporated by reference, see Sec. 63.14.
0
30. Table 3 to subpart DDDDD of part 63 is revised to read as follows:
As stated in Sec. 63.7500, you must comply with the following
applicable work practice standards:
Table 3 to Subpart DDDDD of Part 63--Work Practice Standards
------------------------------------------------------------------------
You must meet the following . .
If your unit is . . . .
------------------------------------------------------------------------
1. A new or existing boiler or process Conduct a tune-up of the boiler
heater with a continuous oxygen trim or process heater every 5
system that maintains an optimum air years as specified in Sec.
to fuel ratio, or a heat input 63.7540.
capacity of less than or equal to 5
million Btu per hour in any of the
following subcategories: unit designed
to burn gas 1; unit designed to burn
gas 2 (other); or unit designed to
burn light liquid, or a limited use
boiler or process heater.
2. A new or existing boiler or process Conduct a tune-up of the boiler
heater without a continuous oxygen or process heater biennially
trim system and with heat input as specified in Sec.
capacity of less than 10 million Btu 63.7540.
per hour in the unit designed to burn
heavy liquid or unit designed to burn
solid fuel subcategories; or a new or
existing boiler or process heater with
heat input capacity of less than 10
million Btu per hour, but greater than
5 million Btu per hour, in any of the
following subcategories: unit designed
to burn gas 1; unit designed to burn
gas 2 (other); or unit designed to
burn light liquid.
3. A new or existing boiler or process Conduct a tune-up of the boiler
heater without a continuous oxygen or process heater annually as
trim system and with heat input specified in Sec. 63.7540.
capacity of 10 million Btu per hour or Units in either the Gas 1 or
greater. Metal Process Furnace
subcategories will conduct
this tune-up as a work
practice for all regulated
emissions under this subpart.
Units in all other
subcategories will conduct
this tune-up as a work
practice for dioxins/furans.
4. An existing boiler or process heater Must have a one-time energy
located at a major source facility, assessment performed by a
not including limited use units. qualified energy assessor. An
energy assessment completed on
or after January 1, 2008, that
meets or is amended to meet
the energy assessment
requirements in this table,
satisfies the energy
assessment requirement. A
facility that operates under
an energy management program
compatible with ISO 50001 that
includes the affected units
also satisfies the energy
assessment requirement. The
energy assessment must include
the following with extent of
the evaluation for items a. to
e. appropriate for the on-site
technical hours listed in Sec.
63.7575:
a. A visual inspection of the
boiler or process heater
system.
[[Page 7199]]
b. An evaluation of operating
characteristics of the boiler
or process heater systems,
specifications of energy using
systems, operating and
maintenance procedures, and
unusual operating constraints.
c. An inventory of major energy
use systems consuming energy
from affected boilers and
process heaters and which are
under the control of the
boiler/process heater owner/
operator.
d. A review of available
architectural and engineering
plans, facility operation and
maintenance procedures and
logs, and fuel usage.
e. A review of the facility's
energy management practices
and provide recommendations
for improvements consistent
with the definition of energy
management practices, if
identified.
f. A list of cost-effective
energy conservation measures
that are within the facility's
control.
g. A list of the energy savings
potential of the energy
conservation measures
identified.
h. A comprehensive report
detailing the ways to improve
efficiency, the cost of
specific improvements,
benefits, and the time frame
for recouping those
investments.
5. An existing or new boiler or process You must operate all CMS during
heater subject to emission limits in startup.
Table 1 or 2 or 11 through 13 to this For startup of a boiler or
subpart during startup. process heater, you must use
one or a combination of the
following clean fuels: natural
gas, synthetic natural gas,
propane, distillate oil,
syngas, ultra-low sulfur
diesel, fuel oil-soaked rags,
kerosene, hydrogen, paper,
cardboard, refinery gas, and
liquefied petroleum gas.
If you start firing coal/solid
fossil fuel, biomass/bio-based
solids, heavy liquid fuel, or
gas 2 (other) gases, you must
vent emissions to the main
stack(s) and engage all of the
applicable control devices
except limestone injection in
fluidized bed combustion (FBC)
boilers, dry scrubber, fabric
filter, selective non-
catalytic reduction (SNCR),
and selective catalytic
reduction (SCR). You must
start your limestone injection
in FBC boilers, dry scrubber,
fabric filter, SNCR, and SCR
systems as expeditiously as
possible. Startup ends when
steam or heat is supplied for
any purpose.
You must comply with all
applicable emission limits at
all times except for startup
or shutdown periods conforming
with this work practice. You
must collect monitoring data
during periods of startup, as
specified in Sec.
63.7535(b). You must keep
records during periods of
startup. You must provide
reports concerning activities
and periods of startup, as
specified in Sec. 63.7555.
6. An existing or new boiler or process You must operate all CMS during
heater subject to emission limits in shutdown.
Tables 1 or 2 or 11 through 13 to this While firing coal/solid fossil
subpart during shutdown. fuel, biomass/bio-based
solids, heavy liquid fuel, or
gas 2 (other) gases during
shutdown, you must vent
emissions to the main stack(s)
and operate all applicable
control devices, except
limestone injection in FBC
boilers, dry scrubber, fabric
filter, SNCR, and SCR.
You must comply with all
applicable emissions limits at
all times except for startup
or shutdown periods conforming
with this work practice. You
must collect monitoring data
during periods of shutdown, as
specified in Sec.
63.7535(b). You must keep
records during periods of
shutdown. You must provide
reports concerning activities
and periods of shutdown, as
specified in Sec. 63.7555.
------------------------------------------------------------------------
0
31. Table 4 to subpart DDDDD of part 63 is revised to read as follows:
As stated in Sec. 63.7500, you must comply with the applicable
operating limits:
Table 4 to Subpart DDDDD of Part 63--Operating Limits for Boilers and
Process Heaters
------------------------------------------------------------------------
When complying with a Table
1, 2, 11, 12, or 13 numerical You must meet these operating limits . .
emission limit using . . . .
------------------------------------------------------------------------
1. Wet PM scrubber control on Maintain the 30-day rolling average
a boiler not using a PM CPMS. pressure drop and the 30-day rolling
average liquid flow rate at or above the
lowest one-hour average pressure drop
and the lowest one-hour average liquid
flow rate, respectively, measured during
the most recent performance test
demonstrating compliance with the PM
emission limitation according to Sec.
63.7530(b) and Table 7 to this subpart.
[[Page 7200]]
2. Wet acid gas (HCl) Maintain the 30-day rolling average
scrubber control on a boiler effluent pH at or above the lowest one-
not using a HCl CEMS. hour average pH and the 30-day rolling
average liquid flow rate at or above the
lowest one-hour average liquid flow rate
measured during the most recent
performance test demonstrating
compliance with the HCl emission
limitation according to Sec.
63.7530(b) and Table 7 to this subpart.
3. Fabric filter control on a. Maintain opacity to less than or equal
units not using a PM CPMS. to 10 percent opacity (daily block
average); or
b. Install and operate a bag leak
detection system according to Sec.
63.7525 and operate the fabric filter
such that the bag leak detection system
alert is not activated more than 5
percent of the operating time during
each 6-month period.
4. Electrostatic precipitator a. This option is for boilers and process
control on units not using a heaters that operate dry control systems
PM CPMS. (i.e., an ESP without a wet scrubber).
Existing and new boilers and process
heaters must maintain opacity to less
than or equal to 10 percent opacity
(daily block average); or
b. This option is only for boilers and
process heaters not subject to PM CPMS
or continuous compliance with an opacity
limit (i.e., COMS). Maintain the 30-day
rolling average total secondary electric
power input of the electrostatic
precipitator at or above the operating
limits established during the
performance test according to Sec.
63.7530(b) and Table 7 to this subpart.
5. Dry scrubber or carbon Maintain the minimum sorbent or carbon
injection control on a injection rate as defined in Sec.
boiler not using a mercury 63.7575 of this subpart.
CEMS.
6. Any other add-on air This option is for boilers and process
pollution control type on heaters that operate dry control
units not using a PM CPMS. systems. Existing and new boilers and
process heaters must maintain opacity to
less than or equal to 10 percent opacity
(daily block average).
7. Fuel analysis............. Maintain the fuel type or fuel mixture
such that the applicable emission rates
calculated according to Sec.
63.7530(c)(1), (2) and/or (3) is less
than the applicable emission limits.
8. Performance testing....... For boilers and process heaters that
demonstrate compliance with a
performance test, maintain the operating
load of each unit such that it does not
exceed 110 percent of the highest hourly
average operating load recorded during
the most recent performance test.
9. Oxygen analyzer system.... For boilers and process heaters subject
to a CO emission limit that demonstrate
compliance with an O2 analyzer system as
specified in Sec. 63.7525(a), maintain
the 30-day rolling average oxygen
content at or above the lowest hourly
average oxygen concentration measured
during the most recent CO performance
test, as specified in Table 8. This
requirement does not apply to units that
install an oxygen trim system since
these units will set the trim system to
the level specified in Sec.
63.7525(a).
10. SO2 CEMS................. For boilers or process heaters subject to
an HCl emission limit that demonstrate
compliance with an SO2 CEMS, maintain
the 30-day rolling average SO2 emission
rate at or below the highest hourly
average SO2 concentration measured
during the most recent HCl performance
test, as specified in Table 8.
------------------------------------------------------------------------
0
32. Table 5 to subpart DDDDD of part 63 is amended by:
0
a. Revising the entry for ``1. Particulate matter.''
0
b. Remove the entry for ``5. Dioxins/Furans''.
0
c. Redesignating the entries for ``2. Hydrogen chloride,'' ``3.
Mercury,'' and ``4. CO'' as ``3. Hydrogen chloride,'' ``4. Mercury,''
and ``5. CO,'' respectively.
0
d. Revising the newly redesignated entries for ``4. Mercury'' and ``5.
CO.''
0
e. Add entry for ``2. Total selected metals.''
The revisions and addition read as follows:
As stated in Sec. 63.7520, you must comply with the following
requirements for performance testing for existing, new or reconstructed
affected sources:
Table 5 to Subpart DDDDD of Part 63--Performance Testing Requirements
------------------------------------------------------------------------
To conduct a performance test
for the following pollutant . You must . . . Using . . .
. .
------------------------------------------------------------------------
1. Filterable PM.............. a. Select sampling Method 1 at 40 CFR
ports location and part 60, appendix
the number of A-1 of this
traverse points. chapter.
b. Determine Method 2, 2F, or 2G
velocity and at 40 CFR part 60,
volumetric flow- appendix A-1 or A-
rate of the stack 2 to part 60 of
gas. this chapter.
c. Determine oxygen Method 3A or 3B at
or carbon dioxide 40 CFR part 60,
concentration of appendix A-2 to
the stack gas. part 60 of this
chapter, or ANSI/
ASME PTC 19.10-
1981.\a\
d. Measure the Method 4 at 40 CFR
moisture content part 60, appendix
of the stack gas. A-3 of this
chapter.
e. Measure the PM Method 5 or 17
emission (positive pressure
concentration. fabric filters
must use Method
5D) at 40 CFR part
60, appendix A-3
or A-6 of this
chapter.
f. Convert Method 19 F-factor
emissions methodology at 40
concentration to CFR part 60,
lb per MMBtu appendix A-7 of
emission rates. this chapter.
2. TSM........................ a. Select sampling Method 1 at 40 CFR
ports location and part 60, appendix
the number of A-1 of this
traverse points. chapter.
[[Page 7201]]
b. Determine Method 2, 2F, or 2G
velocity and at 40 CFR part 60,
volumetric flow- appendix A-1 or A-
rate of the stack 2 of this chapter.
gas.
c. Determine oxygen Method 3A or 3B at
or carbon dioxide 40 CFR part 60,
concentration of appendix A-1 of
the stack gas. this chapter, or
ANSI/ASME PTC
19.10-1981.\a\
d. Measure the Method 4 at 40 CFR
moisture content part 60, appendix
of the stack gas. A-3 of this
chapter.
e. Measure the TSM Method 29 at 40 CFR
emission part 60, appendix
concentration. A-8 of this
chapter
f. Convert Method 19 F-factor
emissions methodology at 40
concentration to CFR part 60,
lb per MMBtu appendix A-7 of
emission rates. this chapter.
3. HCl........................ a. Select sampling Method 1 at 40 CFR
ports location and part 60, appendix
the number of A-1 of this
traverse points. chapter.
b. Determine Method 2, 2F, or 2G
velocity and at 40 CFR part 60,
volumetric flow- appendix A-2 of
rate of the stack this chapter.
gas.
c. Determine oxygen Method 3A or 3B at
or carbon dioxide 40 CFR part 60,
concentration of appendix A-2 of
the stack gas. this chapter, or
ANSI/ASME PTC
19.10-1981.\a\
d. Measure the Method 4 at 40 CFR
moisture content part 60, appendix
of the stack gas. A-3 of this
chapter.
e. Measure the HCl Method 26 or 26A
emission (M26 or M26A) at
concentration. 40 CFR part 60,
appendix A-8 of
this chapter.
f. Convert Method 19 F-factor
emissions methodology at 40
concentration to CFR part 60,
lb per MMBtu appendix A-7 of
emission rates. this chapter.
4. Mercury.................... a. Select sampling Method 1 at 40 CFR
ports location and part 60, appendix
the number of A-1 of this
traverse points. chapter.
b. Determine Method 2, 2F, or 2G
velocity and at 40 CFR part 60,
volumetric flow- appendix A-1 or A-
rate of the stack 2 of this chapter.
gas.
c. Determine oxygen Method 3A or 3B at
or carbon dioxide 40 CFR part 60,
concentration of appendix A-1 of
the stack gas. this chapter, or
ANSI/ASME PTC
19.10-1981.\a\
d. Measure the Method 4 at 40 CFR
moisture content part 60, appendix
of the stack gas. A-3 of this
chapter.
e. Measure the Method 29, 30A, or
mercury emission 30B (M29, M30A, or
concentration. M30B) at 40 CFR
part 60, appendix
A-8 of this
chapter or Method
101A at 40 CFR
part 61, appendix
B of this chapter,
or ASTM Method
D6784.\a\
f. Convert Method 19 F-factor
emissions methodology at 40
concentration to CFR part 60,
lb per MMBtu appendix A-7 of
emission rates. this chapter.
5. CO......................... a. Select the Method 1 at 40 CFR
sampling ports part 60, appendix
location and the A-1 of this
number of traverse chapter.
points.
b. Determine oxygen Method 3A or 3B at
concentration of 40 CFR part 60,
the stack gas. appendix A-3 of
this chapter, or
ASTM D6522-00
(Reapproved 2005),
or ANSI/ASME PTC
19.10-1981.\a\
c. Measure the Method 4 at 40 CFR
moisture content part 60, appendix
of the stack gas. A-3 of this
chapter.
d. Measure the CO Method 10 at 40 CFR
emission part 60, appendix
concentration. A-4 of this
chapter. Use a
measurement span
value of 2 times
the concentration
of the applicable
emission limit.
------------------------------------------------------------------------
* * * * *
0
33. Table 6 to subpart DDDDD of part 63 is revised to read as follows:
As stated in Sec. 63.7521, you must comply with the following
requirements for fuel analysis testing for existing, new or
reconstructed affected sources. However, equivalent methods (as defined
in Sec. 63.7575) may be used in lieu of the prescribed methods at the
discretion of the source owner or operator:
Table 6 to Subpart DDDDD of Part 63--Fuel Analysis Requirements
------------------------------------------------------------------------
To conduct a fuel analysis for
the following pollutant . . . You must . . . Using . . .
------------------------------------------------------------------------
1. Mercury.................... a. Collect fuel Procedure in Sec.
samples. 63.7521(c) or ASTM
D5192 \a\, or ASTM
D7430 \a\, or ASTM
D6883 \a\, or ASTM
D2234/D2234M
\a\(for coal) or
EPA 1631 or EPA
1631E or ASTM
D6323 \a\ (for
solid), or EPA 821-
R-01-013 (for
liquid or solid),
or ASTM D4177 \a\
(for liquid), or
ASTM D4057 \a\
(for liquid), or
equivalent.
b. Composite fuel Procedure in Sec.
samples. 63.7521(d) or
equivalent.
c. Prepare EPA SW-846-3050B
composited fuel \a\ (for solid
samples. samples), EPA SW-
846-3020A \a\ (for
liquid samples),
ASTM D2013/D2013M
\a\ (for coal),
ASTM D5198 \a\
(for biomass), or
EPA 3050 \a\ (for
solid fuel), or
EPA 821-R-01-013
\a\ (for liquid or
solid), or
equivalent.
[[Page 7202]]
d. Determine heat ASTM D5865 \a\ (for
content of the coal) or ASTM E711
fuel type. \a\ (for biomass),
or ASTM D5864 \a\
for liquids and
other solids, or
ASTM D240 \a\ or
equivalent.
e. Determine ASTM D3173 \a\,
moisture content ASTM E871 \a\, or
of the fuel type. ASTM D5864 \a\, or
ASTM D240, or ASTM
D95 \a\ (for
liquid fuels), or
ASTM D4006 \a\
(for liquid
fuels), or ASTM
D4177 \a\ (for
liquid fuels) or
ASTM D4057 \a\
(for liquid
fuels), or
equivalent.
f. Measure mercury ASTM D6722 \a\ (for
concentration in coal), EPA SW-846-
fuel sample. 7471B \a\ (for
solid samples), or
EPA SW-846-7470A
\a\ (for liquid
samples), or
equivalent.
g. Convert Equation 8 in Sec.
concentration into 63.7530.
units of pounds of
mercury per MMBtu
of heat content.
h. Calculate the Equations 10 and 12
mercury emission in Sec. 63.7530.
rate from the
boiler or process
heater in units of
pounds per million
Btu.
2. HCl........................ a. Collect fuel Procedure in Sec.
samples. 63.7521(c) or ASTM
D5192 \a\, or ASTM
D7430 \a\, or ASTM
D6883 \a\, or ASTM
D2234/D2234M \a\
(for coal) or ASTM
D6323 \a\ (for
coal or biomass),
ASTM D4177 \a\
(for liquid fuels)
or ASTM D4057 \a\
(for liquid
fuels), or
equivalent.
b. Composite fuel Procedure in Sec.
samples. 63.7521(d) or
equivalent.
c. Prepare EPA SW-846-3050B
composited fuel \a\ (for solid
samples. samples), EPA SW-
846-3020A \a\ (for
liquid samples),
ASTM D2013/
D2013MSec. \a\
(for coal), or
ASTM D5198Sec.
\a\ (for biomass),
or EPA 3050 \a\ or
equivalent.
d. Determine heat ASTM D5865 \a\ (for
content of the coal) or ASTM E711
fuel type. \a\ (for biomass),
ASTM D5864, ASTM
D240 \a\ or
equivalent.
e. Determine ASTM D3173 \a\ or
moisture content ASTM E871 \a\, or
of the fuel type. D5864 \a\, or ASTM
D240 \a\, or ASTM
D95\a\ (for liquid
fuels), or ASTM
D4006 \a\ (for
liquid fuels), or
ASTM D4177 \a\
(for liquid fuels)
or ASTM D4057 \a\
(for liquid fuels)
or equivalent.
f. Measure chlorine EPA SW-846-9250
concentration in \a\, ASTM D6721
fuel sample. \a\, ASTM D4208
\a\ (for coal), or
EPA SW-846-5050
\a\ or ASTM E776
\a\ (for solid
fuel), or EPA SW-
846-9056 \a\ or SW-
846-9076 \a\ (for
solids or liquids)
or equivalent.
g. Convert Equation 7 in Sec.
concentrations 63.7530.
into units of
pounds of HCl per
MMBtu of heat
content.
h. Calculate the Equations 10 and 11
HCl emission rate in Sec. 63.7530.
from the boiler or
process heater in
units of pounds
per million Btu.
3. Mercury Fuel Specification a. Measure mercury Method 30B (M30B)
for other gas 1 fuels. concentration in at 40 CFR part 60,
the fuel sample appendix A-8 of
and convert to this chapter or
units of ASTM D5954 \a\,
micrograms per ASTM D6350 \a\,
cubic meter. ISO 6978-1:2003(E)
\a\, or ISO 6978-
2:2003(E) \a\, or
EPA-1631 \a\ or
equivalent.
b. Measure mercury Method 29, 30A, or
concentration in 30B (M29, M30A, or
the exhaust gas M30B) at 40 CFR
when firing only part 60, appendix
the other gas 1 A-8 of this
fuel is fired in chapter or Method
the boiler or 101A or Method 102
process heater. at 40 CFR part 61,
appendix B of this
chapter, or ASTM
Method D6784 \a\
or equivalent.
4. TSM for solid fuels........ a. Collect fuel Procedure in Sec.
samples. 63.7521(c) or ASTM
D5192 \a\, or ASTM
D7430 \a\, or ASTM
D6883 \a\, or ASTM
D2234/D2234M \a\
(for coal) or ASTM
D6323 \a\ (for
coal or biomass),
or ASTM D4177
\a\,(for liquid
fuels)or ASTM
D4057 \a\ (for
liquid fuels),or
equivalent.
b. Composite fuel Procedure in Sec.
samples. 63.7521(d) or
equivalent.
c. Prepare EPA SW-846-3050B
composited fuel \a\ (for solid
samples. samples), EPA SW-
846-3020A \a\ (for
liquid samples),
ASTM D2013/D2013M
\a\ (for coal),
ASTM D5198 \a\ or
TAPPI T266 \a\
(for biomass), or
EPA 3050 \a\ or
equivalent.
d. Determine heat ASTM D5865 \a\ (for
content of the coal) or ASTM E711
fuel type. \a\ (for biomass),
or ASTM D5864 \a\
for liquids and
other solids, or
ASTM D240 \a\ or
equivalent.
e. Determine ASTM D3173 \a\ or
moisture content ASTM E871 \a\, or
of the fuel type. D5864, or ASTM
D240 \a\, or ASTM
D95 \a\ (for
liquid fuels), or
ASTM D4006\a\ (for
liquid fuels), or
ASTM D4177 \a\
(for liquid fuels)
or ASTM D4057 \a\
(for liquid
fuels), or
equivalent.
f. Measure TSM ASTM D3683 \a\, or
concentration in ASTM D4606 \ a\,
fuel sample. or ASTM D6357 \a\
or EPA 200.8 \a\
or EPA SW-846-6020
\a\, or EPA SW-846-
6020A \a\, or EPA
SW-846-6010C \a\,
EPA 7060 \a\ or
EPA 7060A \a\ (for
arsenic only), or
EPA SW-846-7740
\a\ (for selenium
only).
g. Convert Equation 9 in Sec.
concentrations 63.7530.
into units of
pounds of TSM per
MMBtu of heat
content.
h. Calculate the Equations 10 and 13
TSM emission rate in Sec. 63.7530.
from the boiler or
process heater in
units of pounds
per million Btu.
------------------------------------------------------------------------
\a\ Incorporated by reference, see Sec. 63.14.
[[Page 7203]]
0
34. Table 7 to subpart DDDDD of part 63 is amended by:
0
a. Revising the entry for ``1. Particulate matter or mercury,''.
0
b. Revising the entry for ``2. Hydrogen Chloride,''.
0
c. Revising the entry for ``3. Mercury,''.
0
d. Revising the entry for ``4. Carbon monoxide''.
The revisions read as follows:
As stated in Sec. 63.7520, you must comply with the following
requirements for establishing operating limits:
Table 7 to Subpart DDDDD of Part 63--Establishing Operating Limits
----------------------------------------------------------------------------------------------------------------
And your operating According to the
If you have an applicable limits are based You must . . . Using . . . following
emission limit for . . . on . . . requirements
----------------------------------------------------------------------------------------------------------------
1. PM, TSM, or mercury.......... a. Wet scrubber i. Establish a (1) Data from the (a) You must
operating site-specific scrubber pressure collect scrubber
parameters. minimum scrubber drop and liquid pressure drop and
pressure drop and flow rate liquid flow rate
minimum flow rate monitors and the data every 15
operating limit PM or mercury minutes during
according to Sec. performance test. the entire period
63.7530(b). of the
performance
tests.
(b) Determine the
lowest hourly
average scrubber
pressure drop and
liquid flow rate
by computing the
hourly averages
using all of the
15-minute
readings taken
during each
performance test.
b. Electrostatic i. Establish a (1) Data from the (a) You must
precipitator site-specific voltage and collect secondary
operating minimum total secondary voltage and
parameters secondary amperage monitors secondary
(option only for electric power during the PM or amperage for each
units that input according mercury ESP cell and
operate wet to Sec. performance test. calculate total
scrubbers). 63.7530(b). secondary
electric power
input data every
15 minutes during
the entire period
of the
performance
tests.
(b) Determine the
average total
secondary
electric power
input by
computing the
hourly averages
using all of the
15-minute
readings taken
during each
performance test.
2. HCl.......................... a. Wet scrubber i. Establish site- (1) Data from the (a) You must
operating specific minimum pressure drop, collect pH and
parameters. pressure drop, pH, and liquid liquid flow-rate
effluent pH, and flow-rate data every 15
flow rate monitors and the minutes during
operating limits HCl performance the entire period
according to Sec. test. of the
63.7530(b). performance
tests.
(b) Determine the
hourly average pH
and liquid flow
rate by computing
the hourly
averages using
all of the 15-
minute readings
taken during each
performance test.
b. Dry scrubber i. Establish a (1) Data from the (a) You must
operating site-specific sorbent injection collect sorbent
parameters. minimum sorbent rate monitors and injection rate
injection rate HCl or mercury data every 15
operating limit performance test. minutes during
according to Sec. the entire period
63.7530(b). If of the
different acid performance
gas sorbents are tests.
used during the
HCl performance
test, the average
value for each
sorbent becomes
the site-specific
operating limit
for that sorbent.
(b) Determine the
hourly average
sorbent injection
rate by computing
the hourly
averages using
all of the 15-
minute readings
taken during each
performance test.
(c) Determine the
lowest hourly
average of the
three test run
averages
established
during the
performance test
as your operating
limit. When your
unit operates at
lower loads,
multiply your
sorbent injection
rate by the load
fraction (e.g.,
for 50 percent
load, multiply
the injection
rate operating
limit by 0.5) to
determine the
required
injection rate.
c. Alternative i. Establish a (1) Data from SO2 (a) You must
Maximum SO2 site-specific CEMS and the HCl collect the SO2
emission rate. maximum SO2 performance test. emissions data
emission rate according to Sec.
operating limit 63.7525(m)
according to Sec. during the most
63.7530(b). recent HCl
performance
tests.
[[Page 7204]]
(b) The maximum
SO2 emission rate
is equal to the
lowest hourly
average SO2
emission rate
measured during
the most recent
HCl performance
tests.
3. Mercury...................... a. Activated i. Establish a (1) Data from the (a) You must
carbon injection. site-specific activated carbon collect activated
minimum activated rate monitors and carbon injection
carbon injection mercury rate data every
rate operating performance test. 15 minutes during
limit according the entire period
to Sec. of the
63.7530(b). performance
tests.
(b) Determine the
hourly average
activated carbon
injection rate by
computing the
hourly averages
using all of the
15-minute
readings taken
during each
performance test.
(c) Determine the
lowest hourly
average
established
during the
performance test
as your operating
limit. When your
unit operates at
lower loads,
multiply your
activated carbon
injection rate by
the load fraction
(e.g., actual
heat input
divided by heat
input during
performance test,
for 50 percent
load, multiply
the injection
rate operating
limit by 0.5) to
determine the
required
injection rate.
4. Carbon monoxide.............. a. Oxygen......... i. Establish a (1) Data from the (a) You must
unit-specific oxygen analyzer collect oxygen
limit for minimum system specified data every 15
oxygen level in Sec. minutes during
according to Sec. 63.7525(a). the entire period
63.7520. of the
performance
tests.
(b) Determine the
hourly average
oxygen
concentration by
computing the
hourly averages
using all of the
15-minute
readings taken
during each
performance test.
(c) Determine the
lowest hourly
average
established
during the
performance test
as your minimum
operating limit.
* * * * * * *
----------------------------------------------------------------------------------------------------------------
0
35. Table 8 to subpart DDDDD of part 63 is revised to read as follows:
As stated in Sec. 63.7540, you must show continuous compliance
with the emission limitations for each boiler or process heater
according to the following:
Table 8 to Subpart DDDDD of Part 63--Demonstrating Continuous Compliance
------------------------------------------------------------------------
If you must meet the
following operating limits or You must demonstrate continuous
work practice standards . . . compliance by . . .
------------------------------------------------------------------------
1. Opacity................... a. Collecting the opacity monitoring
system data according to Sec.
63.7525(c) and Sec. 63.7535; and
b. Reducing the opacity monitoring data
to 6-minute averages; and
c. Maintaining opacity to less than or
equal to 10 percent (daily block
average).
2. PM CPMS................... a. Collecting the PM CPMS output data
according to Sec. 63.7525;
b. Reducing the data to 30-day rolling
averages; and
c. Maintaining the 30-day rolling average
PM CPMS output data to less than the
operating limit established during the
performance test according to Sec.
63.7530(b)(4).
3. Fabric Filter Bag Leak Installing and operating a bag leak
Detection Operation. detection system according to Sec.
63.7525 and operating the fabric filter
such that the requirements in Sec.
63.7540(a)(9) are met.
4. Wet Scrubber Pressure Drop a. Collecting the pressure drop and
and Liquid Flow-rate. liquid flow rate monitoring system data
according to Sec. Sec. 63.7525 and
63.7535; and
b. Reducing the data to 30-day rolling
averages; and
c. Maintaining the 30-day rolling average
pressure drop and liquid flow-rate at or
above the operating limits established
during the performance test according to
Sec. 63.7530(b).
5. Wet Scrubber pH........... a. Collecting the pH monitoring system
data according to Sec. Sec. 63.7525
and 63.7535; and
[[Page 7205]]
b. Reducing the data to 30-day rolling
averages; and
c. Maintaining the 30-day rolling average
pH at or above the operating limit
established during the performance test
according to Sec. 63.7530(b).
6. Dry Scrubber Sorbent or a. Collecting the sorbent or carbon
Carbon Injection Rate. injection rate monitoring system data
for the dry scrubber according to Sec.
Sec. 63.7525 and 63.7535; and
b. Reducing the data to 30-day rolling
averages; and
c. Maintaining the 30-day rolling average
sorbent or carbon injection rate at or
above the minimum sorbent or carbon
injection rate as defined in Sec.
63.7575.
7. Electrostatic Precipitator a. Collecting the total secondary
Total Secondary Electric electric power input monitoring system
Power Input. data for the electrostatic precipitator
according to Sec. Sec. 63.7525 and
63.7535; and
b. Reducing the data to 30-day rolling
averages; and
c. Maintaining the 30-day rolling average
total secondary electric power input at
or above the operating limits
established during the performance test
according to Sec. 63.7530(b).
8. Emission limits using fuel a. Conduct monthly fuel analysis for HCl
analysis. or mercury or TSM according to Table 6
to this subpart; and
b. Reduce the data to 12-month rolling
averages; and
c. Maintain the 12-month rolling average
at or below the applicable emission
limit for HCl or mercury or TSM in
Tables 1 and 2 or 11 through 13 to this
subpart.
9. Oxygen content............ a. Continuously monitor the oxygen
content using an oxygen analyzer system
according to Sec. 63.7525(a). This
requirement does not apply to units that
install an oxygen trim system since
these units will set the trim system to
the level specified in Sec.
63.7525(a)(2).
b. Reducing the data to 30-day rolling
averages; and
c. Maintain the 30-day rolling average
oxygen content at or above the lowest
hourly average oxygen level measured
during the most recent CO performance
test.
10. Boiler or process heater a. Collecting operating load data or
operating load. steam generation data every 15 minutes.
b. Maintaining the operating load such
that it does not exceed 110 percent of
the highest hourly average operating
load recorded during the most recent
performance test according to Sec.
63.7520(c).
11. SO2 emissions using SO2 a. Collecting the SO2 CEMS output data
CEMS. according to Sec. 63.7525;
b. Reducing the data to 30-day rolling
averages; and
c. Maintaining the 30-day rolling average
SO2 CEMS emission rate to a level at or
below the minimum hourly SO2 rate
measured during the most recent HCl
performance test according to Sec.
63.7530.
------------------------------------------------------------------------
0
36. Table 9 to subpart DDDDD of part 63 is amended by revising the
entry for ``1. Compliance report'' to read as follows:
As stated in Sec. 63.7550, you must comply with the following
requirements for reports:
Table 9 to Subpart DDDDD of Part 63--Reporting Requirements
------------------------------------------------------------------------
The report must You must submit
You must submit a(n) contain . . . the report . . .
------------------------------------------------------------------------
1. Compliance report............ a. Information Semiannually,
required in Sec. annually,
63.7550(c)(1) biennially, or
through (5); and every 5 years
according to the
requirements in
Sec.
63.7550(b).
* * * * * * *
------------------------------------------------------------------------
0
37. Table 10 to subpart DDDDD of part 63 is amended by:
0
a. Revising the entry for ``Sec. 63.6(i)''.
0
b. Revising the entry for ``Sec. 63.7(e)(1)''.
0
c. Revising the entry for ``63.8(g)''.
0
d. Revising the entry for ``Sec. 63.10(e) and (f)''.
0
e. Adding an entry for ``Sec. 63.10(e)''.
The revisions and addition read as follows.
As stated in Sec. 63.7565, you must comply with the applicable
General Provisions according to the following:
Table 10 to Subpart DDDDD of Part 63--Applicability of General
Provisions to Subpart DDDDD
------------------------------------------------------------------------
Applies to subpart
Citation Subject DDDDD
------------------------------------------------------------------------
* * * * * * *
Sec. 63.6(i)................ Extension of Yes. Note:
compliance. Facilities may
also request
extensions of
compliance for the
installation of
combined heat and
power, waste heat
recovery, or gas
pipeline or fuel
feeding
infrastructure as
a means of
complying with
this subpart.
[[Page 7206]]
* * * * * * *
Sec. 63.7(e)(1)............. Conditions for No. Subpart DDDDD
conducting specifies
performance tests. conditions for
conducting
performance tests
at Sec.
63.7520(a) to (c).
* * * * * * *
Sec. 63.8(g)................ Reduction of Yes.
monitoring data.
* * * * * * *
Sec. 63.10(e)............... Additional Yes.
reporting
requirements for
sources with CMS.
Sec. 63.10(f)............... Waiver of Yes.
recordkeeping or
reporting
requirements.
* * * * * * *
------------------------------------------------------------------------
0
38. Add Table 11 to subpart DDDDD of part 63 to read as follows:
Table 11 to Subpart DDDDD of Part 63--Alternative Emission Limits for New or Reconstructed Boilers and Process
Heaters That Commenced Construction or Reconstruction After June 4, 2010, and Before May 20, 2011
----------------------------------------------------------------------------------------------------------------
The emissions must
not exceed the
following emission Using this specified
If your boiler or process heater For the following pollutants . . limits, except sampling volume or
is in this subcategory . . . . during periods of test run duration .
startup and shutdown . .
. . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories a. HCl.......................... 0.022 lb per MMBtu For M26A, collect a
designed to burn solid fuel. of heat input. minimum of 1 dscm
per run; for M26
collect a minimum
of 120 liters per
run.
2. Units in all subcategories a. Mercury...................... 8.0E-07 \a\ lb per For M29, collect a
designed to burn solid fuel that MMBtu of heat input. minimum of 4 dscm
combust at least 10 percent per run; for M30A
biomass/bio-based solids on an or M30B, collect a
annual heat input basis and less minimum sample as
than 10 percent coal/solid fossil specified in the
fuels on an annual heat input method; for ASTM
basis. D6784 \b\ collect a
minimum of 4 dscm.
3. Units in all subcategories a. Mercury...................... 2.0E-06 lb per MMBtu For M29, collect a
designed to burn solid fuel that of heat input. minimum of 4 dscm
combust at least 10 percent coal/ per run; for M30A
solid fossil fuels on an annual or M30B, collect a
heat input basis and less than 10 minimum sample as
percent biomass/bio-based solids specified in the
on an annual heat input basis. method; for ASTM
D6784 \b\ collect a
minimum of 4 dscm.
4. Units designed to burn coal/ a. Filterable PM (or TSM)....... 1.1E-03 lb per MMBtu Collect a minimum of
solid fossil fuel. of heat input; or 3 dscm per run.
(2.3E-05 lb per
MMBtu of heat
input).
5. Pulverized coal boilers a. Carbon monoxide (CO) (or 130 ppm by volume on 1 hr minimum
designed to burn coal/solid CEMS). a dry basis sampling time.
fossil fuel. corrected to 3
percent oxygen, 3-
run average; or
(320 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 30-
day rolling
average).
6. Stokers designed to burn coal/ a. CO (or CEMS)................. 130 ppm by volume on 1 hr minimum
solid fossil fuel. a dry basis sampling time.
corrected to 3
percent oxygen, 3-
run average; or
(340 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 10-
day rolling
average).
7. Fluidized bed units designed to a. CO (or CEMS)................. 130 ppm by volume on 1 hr minimum
burn coal/solid fossil fuel. a dry basis sampling time.
corrected to 3
percent oxygen, 3-
run average; or
(230 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 30-
day rolling
average).
[[Page 7207]]
8. Fluidized bed units with an a. CO (or CEMS)................. 140 ppm by volume on 1 hr minimum
integrated heat exchanger a dry basis sampling time.
designed to burn coal/solid corrected to 3
fossil fuel. percent oxygen, 3-
run average; or
(150 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 30-
day rolling
average).
9. Stokers/sloped grate/others a. CO (or CEMS)................. 620 ppm by volume on 1 hr minimum
designed to burn wet biomass fuel. a dry basis sampling time.
corrected to 3
percent oxygen, 3-
run average; or
(390 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 30-
day rolling
average).
b. Filterable PM (or TSM)....... 3.0E-02 lb per MMBtu Collect a minimum of
of heat input; or 2 dscm per run.
(2.6E-05 lb per
MMBtu of heat
input).
10. Stokers/sloped grate/others a. CO........................... 560 ppm by volume on 1 hr minimum
designed to burn kiln-dried a dry basis sampling time.
biomass fuel. corrected to 3
percent oxygen.
b. Filterable PM (or TSM)....... 3.0E-02 lb per MMBtu Collect a minimum of
of heat input; or 2 dscm per run.
(4.0E-03 lb per
MMBtu of heat
input).
11. Fluidized bed units designed a. CO (or CEMS)................. 230 ppm by volume on 1 hr minimum
to burn biomass/bio-based solids. a dry basis sampling time.
corrected to 3
percent oxygen, 3-
run average; or
(310 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 30-
day rolling
average).
b. Filterable PM (or TSM)....... 9.8E-03 lb per MMBtu Collect a minimum of
of heat input; or 3 dscm per run
(8.3E-05 \a\ lb per
MMBtu of heat
input).
12. Suspension burners designed to a. CO (or CEMS)................. 2,400 ppm by volume 1 hr minimum
burn biomass/bio-based solids. on a dry basis sampling time.
corrected to 3
percent oxygen, 3-
run average; or
(2,000 ppm by
volume on a dry
basis corrected to
3 percent oxygen,
10-day rolling
average).
b. Filterable PM (or TSM)....... 3.0E-02 lb per MMBtu Collect a minimum of
of heat input; or 2 dscm per run.
(6.5E-03 lb per
MMBtu of heat
input).
13. Dutch Ovens/Pile burners a. CO (or CEMS)................. 1,010 ppm by volume 1 hr minimum
designed to burn biomass/bio- on a dry basis sampling time.
based solids. corrected to 3
percent oxygen, 3-
run average; or
(520 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 10-
day rolling
average).
b. Filterable PM (or TSM)....... 8.0E-03 lb per MMBtu Collect a minimum of
of heat input; or 3 dscm per run.
(3.9E-05 lb per
MMBtu of heat
input).
14. Fuel cell units designed to a. CO........................... 910 ppm by volume on 1 hr minimum
burn biomass/bio-based solids. a dry basis sampling time.
corrected to 3
percent oxygen.
b. Filterable PM (or TSM)....... 2.0E-02 lb per MMBtu Collect a minimum of
of heat input; or 2 dscm per run.
(2.9E-05 lb per
MMBtu of heat
input).
15. Hybrid suspension grate boiler a. CO (or CEMS)................. 1,100 ppm by volume 1 hr minimum
designed to burn biomass/bio- on a dry basis sampling time.
based solids. corrected to 3
percent oxygen, 3-
run average; or
(900 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 30-
day rolling
average).
b. Filterable PM (or TSM)....... 2.6E-02 lb per MMBtu Collect a minimum of
of heat input; or 3 dscm per run.
(4.4E-04 lb per
MMBtu of heat
input).
16. Units designed to burn liquid a. HCl.......................... 4.4E-04 lb per MMBtu For M26A: Collect a
fuel. of heat input. minimum of 2 dscm
per run; for M26,
collect a minimum
of 240 liters per
run.
[[Page 7208]]
b. Mercury...................... 4.8E-07 \a\ lb per For M29, collect a
MMBtu of heat input. minimum of 4 dscm
per run; for M30A
or M30B, collect a
minimum sample as
specified in the
method; for ASTM
D6784 \b\ collect a
minimum of 4 dscm.
17. Units designed to burn heavy a. CO........................... 130 ppm by volume on 1 hr minimum
liquid fuel. a dry basis sampling time.
corrected to 3
percent oxygen, 3-
run average.
b. Filterable PM (or TSM)....... 1.3E-02 lb per MMBtu Collect a minimum of
of heat input; or 3 dscm per run.
(7.5E-05 lb per
MMBtu of heat
input).
18. Units designed to burn light a. CO........................... 130 ppm by volume on 1 hr minimum
liquid fuel. a dry basis sampling time.
corrected to 3
percent oxygen.
b. Filterable PM (or TSM)....... 2.0E-03 \a\ lb per Collect a minimum of
MMBtu of heat 3 dscm per run
input; or (2.9E-05
lb per MMBtu of
heat input).
19. Units designed to burn liquid a. CO........................... 130 ppm by volume on 1 hr minimum
fuel that are non-continental a dry basis sampling time.
units. corrected to 3
percent oxygen, 3-
run average based
on stack test.
b. Filterable PM (or TSM)....... 2.3E-02 lb per MMBtu Collect a minimum of
of heat input; or 4 dscm per run
(8.6E-04 lb per
MMBtu of heat
input).
20. Units designed to burn gas 2 a. CO........................... 130 ppm by volume on 1 hr minimum
(other) gases. a dry basis sampling time.
corrected to 3
percent oxygen.
b. HCl.......................... 1.7E-03 lb per MMBtu For M26A, collect a
of heat input. minimum of 2 dscm
per run; for M26,
collect a minimum
of 240 liters per
run.
c. Mercury...................... 7.9E-06 lb per MMBtu For M29, collect a
of heat input. minimum of 3 dscm
per run; for M30A
or M30B, collect a
minimum sample as
specified in the
method; for ASTM
D6784 \b\ collect a
minimum of 3 dscm.
d. Filterable PM (or TSM)....... 6.7E-03 lb per MMBtu Collect a minimum of
of heat input; or 3 dscm per run
(2.1E-04 lb per
MMBtu of heat
input).
----------------------------------------------------------------------------------------------------------------
\a\ If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant
for at least 2 consecutive years show that your emissions are at or below this limit, you can skip testing
according to Sec. 63.7515 if all of the other provisions of Sec. 63.7515 are met. For all other pollutants
that do not contain a footnote ``a'', your performance tests for this pollutant for at least 2 consecutive
years must show that your emissions are at or below 75 percent of this limit in order to qualify for skip
testing.
\b\ Incorporated by reference, see Sec. 63.14.
0
39. Add Table 12 to subpart DDDDD of part 63 to read as follows:
Table 12 to Subpart DDDDD of Part 63--Alternative Emission Limits for New or Reconstructed Boilers and Process
Heaters that Commenced Construction or Reconstruction after May 20, 2011, and Before December 23, 2011
----------------------------------------------------------------------------------------------------------------
The emissions must
not exceed the
following emission Using this specified
If your boiler or process heater For the following pollutants . . limits, except sampling volume or
is in this subcategory . . . . during periods of test run duration .
startup and shutdown . .
. . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories a. HCl.......................... 0.022 lb per MMBtu For M26A, collect a
designed to burn solid fuel. of heat input. minimum of 1 dscm
per run; for M26
collect a minimum
of 120 liters per
run.
b. Mercury...................... 3.5E-06 \a\ lb per For M29, collect a
MMBtu of heat input. minimum of 3 dscm
per run; for M30A
or M30B, collect a
minimum sample as
specified in the
method; for ASTM
D6784 \b\ collect a
minimum of 3 dscm.
2. Units design to burn coal/solid a. Filterable PM (or TSM)....... 1.1E-03 lb per MMBtu Collect a minimum of
fossil fuel. of heat input; or 3 dscm per run.
(2.3E-05 lb per
MMBtu of heat
input).
[[Page 7209]]
3. Pulverized coal boilers a. Carbon monoxide (CO) (or 130 ppm by volume on 1 hr minimum
designed to burn coal/solid CEMS). a dry basis sampling time.
fossil fuel. corrected to 3
percent oxygen, 3-
run average; or
(320 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 30-
day rolling
average).
4. Stokers designed to burn coal/ a. CO (or CEMS)................. 130 ppm by volume on 1 hr minimum
solid fossil fuel. a dry basis sampling time.
corrected to 3
percent oxygen, 3-
run average; or
(340 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 10-
day rolling
average).
5. Fluidized bed units designed to a. CO (or CEMS)................. 130 ppm by volume on 1 hr minimum
burn coal/solid fossil fuel. a dry basis sampling time.
corrected to 3
percent oxygen, 3-
run average; or
(230 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 30-
day rolling
average).
6. Fluidized bed units with an a. CO (or CEMS)................. 140 ppm by volume on 1 hr minimum
integrated heat exchanger a dry basis sampling time.
designed to burn coal/solid corrected to 3
fossil fuel. percent oxygen, 3-
run average; or
(150 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 30-
day rolling
average).
7. Stokers/sloped grate/others a. CO (or CEMS)................. 620 ppm by volume on 1 hr minimum
designed to burn wet biomass fuel. a dry basis sampling time.
corrected to 3
percent oxygen, 3-
run average; or
(390 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 30-
day rolling
average).
b. Filterable PM (or TSM)....... 3.0E-02 lb per MMBtu Collect a minimum of
of heat input; or 2 dscm per run.
(2.6E-05 lb per
MMBtu of heat
input).
8. Stokers/sloped grate/others a. CO........................... 460 ppm by volume on 1 hr minimum
designed to burn kiln-dried a dry basis sampling time.
biomass fuel. corrected to 3
percent oxygen.
b. Filterable PM (or TSM)....... 3.0E-02 lb per MMBtu Collect a minimum of
of heat input; or 2 dscm per run.
(4.0E-03 lb per
MMBtu of heat
input).
9. Fluidized bed units designed to a. CO (or CEMS)................. 260 ppm by volume on 1 hr minimum
burn biomass/bio-based solids. a dry basis sampling time.
corrected to 3
percent oxygen, 3-
run average; or
(310 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 30-
day rolling
average).
b. Filterable PM (or TSM)....... 9.8E-03 lb per MMBtu Collect a minimum of
of heat input; or 3 dscm per run.
(8.3E-05 \a\ lb per
MMBtu of heat
input).
10. Suspension burners designed to a. CO (or CEMS)................. 2,400 ppm by volume 1 hr minimum
burn biomass/bio-based solids. on a dry basis sampling time.
corrected to 3
percent oxygen, 3-
run average; or
(2,000 ppm by
volume on a dry
basis corrected to
3 percent oxygen,
10-day rolling
average).
b. Filterable PM (or TSM)....... 3.0E-02 lb per MMBtu Collect a minimum of
of heat input; or 2 dscm per run.
(6.5E-03 lb per
MMBtu of heat
input).
11. Dutch Ovens/Pile burners a. CO (or CEMS)................. 470 ppm by volume on 1 hr minimum
designed to burn biomass/bio- a dry basis sampling time.
based solids. corrected to 3
percent oxygen, 3-
run average; or
(520 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 10-
day rolling
average).
b. Filterable PM (or TSM)....... 3.2E-03 lb per MMBtu Collect a minimum of
of heat input; or 3 dscm per run.
(3.9E-05 lb per
MMBtu of heat
input).
[[Page 7210]]
12. Fuel cell units designed to a. CO........................... 910 ppm by volume on 1 hr minimum
burn biomass/bio-based solids. a dry basis sampling time.
corrected to 3
percent oxygen.
b. Filterable PM (or TSM)....... 2.0E-02 lb per MMBtu Collect a minimum of
of heat input; or 2 dscm per run.
(2.9E-05 lb per
MMBtu of heat
input).
13. Hybrid suspension grate boiler a. CO (or CEMS)................. 1,500 ppm by volume 1 hr minimum
designed to burn biomass/bio- on a dry basis sampling time.
based solids. corrected to 3
percent oxygen, 3-
run average; or
(900 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 30-
day rolling
average).
b. Filterable PM (or TSM)....... 2.6E-02 lb per MMBtu Collect a minimum of
of heat input; or 3 dscm per run.
(4.4E-04 lb per
MMBtu of heat
input).
14. Units designed to burn liquid a. HCl.......................... 4.4E-04 lb per MMBtu For M26A: Collect a
fuel. of heat input. minimum of 2 dscm
per run; for M26,
collect a minimum
of 240 liters per
run.
b. Mercury...................... 4.8E-07 \a\ lb per For M29, collect a
MMBtu of heat input. minimum of 4 dscm
per run; for M30A
or M30B, collect a
minimum sample as
specified in the
method; for ASTM
D6784 \b\ collect a
minimum of 4 dscm.
15. Units designed to burn heavy a. CO........................... 130 ppm by volume on 1 hr minimum
liquid fuel. a dry basis sampling time.
corrected to 3
percent oxygen, 3-
run average.
b. Filterable PM (or TSM)....... 1.3E-02 lb per MMBtu Collect a minimum of
of heat input; or 2 dscm per run.
(7.5E-05 lb per
MMBtu of heat
input).
16. Units designed to burn light a. CO........................... 130 ppm by volume on 1 hr minimum
liquid fuel. a dry basis sampling time.
corrected to 3
percent oxygen.
b. Filterable PM (or TSM)....... 1.3E-03 \a\ lb per Collect a minimum of
MMBtu of heat 3 dscm per run.
input; or (2.9E-05
lb per MMBtu of
heat input).
17. Units designed to burn liquid a. CO........................... 130 ppm by volume on 1 hr minimum
fuel that are non-continental a dry basis sampling time.
units. corrected to 3
percent oxygen, 3-
run average based
on stack test.
b. Filterable PM (or TSM)....... 2.3E-02 lb per MMBtu Collect a minimum of
of heat input; or 4 dscm per run.
(8.6E-04 lb per
MMBtu of heat
input).
18. Units designed to burn gas 2 a. CO........................... 130 ppm by volume on 1 hr minimum
(other) gases. a dry basis sampling time.
corrected to 3
percent oxygen.
b. HCl.......................... 1.7E-03 lb per MMBtu For M26A, Collect a
of heat input. minimum of 2 dscm
per run; for M26,
collect a minimum
of 240 liters per
run.
c. Mercury...................... 7.9E-06 lb per MMBtu For M29, collect a
of heat input. minimum of 3 dscm
per run; for M30A
or M30B, collect a
minimum sample as
specified in the
method; for ASTM
D6784 \b\ collect a
minimum of 3 dscm.
d. Filterable PM (or TSM)....... 6.7E-03 lb per MMBtu Collect a minimum of
of heat input; or 3 dscm per run.
(2.1E-04 lb per
MMBtu of heat
input).
----------------------------------------------------------------------------------------------------------------
\a\ If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant
for at least 2 consecutive years show that your emissions are at or below this limit, you can skip testing
according to Sec. 63.7515 if all of the other provision of Sec. 63.7515 are met. For all other pollutants
that do not contain a footnote ``a'', your performance tests for this pollutant for at least 2 consecutive
years must show that your emissions are at or below 75 percent of this limit in order to qualify for skip
testing.
\b\ Incorporated by reference, see Sec. 63.14.
0
40. Add Table 13 to subpart DDDDD of part 63 to read as follows:
[[Page 7211]]
Table 13 to Subpart DDDDD of Part 63--Alternative Emission Limits for New or Reconstructed Boilers and Process
Heaters That Commenced Construction or Reconstruction After December 23, 2011, and Before January 31, 2013
----------------------------------------------------------------------------------------------------------------
The emissions must
not exceed the
following emission Using this specified
If your boiler or process heater For the following pollutants . . limits, except sampling volume or
is in this subcategory . . . . during periods of test run duration .
startup and shutdown . .
. . .
----------------------------------------------------------------------------------------------------------------
1. Units in all subcategories a. HCl.......................... 0.022 lb per MMBtu For M26A, collect a
designed to burn solid fuel. of heat input. minimum of 1 dscm
per run; for M26
collect a minimum
of 120 liters per
run.
b. Mercury...................... 8.6E-07 \a\ lb per For M29, collect a
MMBtu of heat input. minimum of 4 dscm
per run; for M30A
or M30B, collect a
minimum sample as
specified in the
method; for ASTM
D6784 \b\ collect a
minimum of 4 dscm.
2. Pulverized coal boilers a. Carbon monoxide (CO) (or 130 ppm by volume on 1 hr minimum
designed to burn coal/solid CEMS). a dry basis sampling time.
fossil fuel. corrected to 3
percent oxygen, 3-
run average; or
(320 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 30-
day rolling
average).
b. Filterable PM (or TSM)....... 1.1E-03 lb per MMBtu Collect a minimum of
of heat input; or 3 dscm per run.
(2.8E-05 lb per
MMBtu of heat
input).
3. Stokers designed to burn coal/ a. CO (or CEMS)................. 130 ppm by volume on 1 hr minimum
solid fossil fuel. a dry basis sampling time.
corrected to 3
percent oxygen, 3-
run average; or
(340 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 10-
day rolling
average).
b. Filterable PM (or TSM)....... 2.8E-02 lb per MMBtu Collect a minimum of
of heat input; or 2 dscm per run.
(2.3E-05 lb per
MMBtu of heat
input).
4. Fluidized bed units designed to a. CO (or CEMS)................. 130 ppm by volume on 1 hr minimum
burn coal/solid fossil fuel. a dry basis sampling time.
corrected to 3
percent oxygen, 3-
run average; or
(230 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 30-
day rolling
average).
b. Filterable PM (or TSM)....... 1.1E-03 lb per MMBtu Collect a minimum of
of heat input; or 3 dscm per run.
(2.3E-05 lb per
MMBtu of heat
input).
5. Fluidized bed units with an a. CO (or CEMS)................. 140 ppm by volume on 1 hr minimum
integrated heat exchanger a dry basis sampling time.
designed to burn coal/solid corrected to 3
fossil fuel. percent oxygen, 3-
run average; or
(150 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 30-
day rolling
average).
b. Filterable PM (or TSM)....... 1.1E-03 lb per MMBtu Collect a minimum of
of heat input; or 3 dscm per run.
(2.3E-05 lb per
MMBtu of heat
input).
6. Stokers/sloped grate/others a. CO (or CEMS)................. 620 ppm by volume on 1 hr minimum
designed to burn wet biomass fuel. a dry basis sampling time.
corrected to 3
percent oxygen, 3-
run average; or
(410 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 10-
day rolling
average).
b. Filterable PM (or TSM)....... 3.0E-02 lb per MMBtu Collect a minimum of
of heat input; or 2 dscm per run.
(2.6E-05 lb per
MMBtu of heat
input).
7. Stokers/sloped grate/others a. CO........................... 460 ppm by volume on 1 hr minimum
designed to burn kiln-dried a dry basis sampling time.
biomass fuel. corrected to 3
percent oxygen.
b. Filterable PM (or TSM)....... 3.2E-01 lb per MMBtu Collect a minimum of
of heat input; or 2 dscm per run.
(4.0E-03 lb per
MMBtu of heat
input).
8. Fluidized bed units designed to a. CO (or CEMS)................. 230 ppm by volume on 1 hr minimum
burn biomass/bio-based solids. a dry basis sampling time.
corrected to 3
percent oxygen, 3-
run average; or
(310 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 30-
day rolling
average).
[[Page 7212]]
b. Filterable PM (or TSM)....... 9.8E-03 lb per MMBtu Collect a minimum of
of heat input; or 3 dscm per run.
(8.3E-05 \a\ lb per
MMBtu of heat
input).
9. Suspension burners designed to a. CO (or CEMS)................. 2,400 ppm by volume 1 hr minimum
burn biomass/bio-based solids. on a dry basis sampling time.
corrected to 3
percent oxygen, 3-
run average; or
(2,000 ppm by
volume on a dry
basis corrected to
3 percent oxygen,
10-day rolling
average).
b. Filterable PM (or TSM)....... 5.1E-02 lb per MMBtu Collect a minimum of
of heat input; or 2 dscm per run.
(6.5E-03 lb per
MMBtu of heat
input).
10. Dutch Ovens/Pile burners a. CO (or CEMS)................. 810 ppm by volume on 1 hr minimum
designed to burn biomass/bio- a dry basis sampling time.
based solids. corrected to 3
percent oxygen, 3-
run average; or
(520 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 10-
day rolling
average).
b. Filterable PM (or TSM)....... 3.6E-02 lb per MMBtu Collect a minimum of
of heat input; or 2 dscm per run.
(3.9E-05 lb per
MMBtu of heat
input).
11. Fuel cell units designed to a. CO........................... 910 ppm by volume on 1 hr minimum
burn biomass/bio-based solids. a dry basis sampling time.
corrected to 3
percent oxygen.
b. Filterable PM (or TSM)....... 2.0E-02 lb per MMBtu Collect a minimum of
of heat input; or 2 dscm per run.
(2.9E-05 lb per
MMBtu of heat
input).
12. Hybrid suspension grate boiler a. CO (or CEMS)................. 1,500 ppm by volume 1 hr minimum
designed to burn biomass/bio- on a dry basis sampling time.
based solids. corrected to 3
percent oxygen, 3-
run average; or
(900 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 30-
day rolling
average).
b. Filterable PM (or TSM)....... 2.6E-02 lb per MMBtu Collect a minimum of
of heat input; or 3 dscm per run.
(4.4E-04 lb per
MMBtu of heat
input).
13. Units designed to burn liquid a. HCl.......................... 1.2E-03 lb per MMBtu For M26A: Collect a
fuel. of heat input. minimum of 2 dscm
per run; for M26,
collect a minimum
of 240 liters per
run.
b. Mercury...................... 4.9E-07 \a\ lb per For M29, collect a
MMBtu of heat input. minimum of 4 dscm
per run; for M30A
or M30B, collect a
minimum sample as
specified in the
method; for ASTM
D6784 \b\ collect a
minimum of 4 dscm.
14. Units designed to burn heavy a. CO (or CEMS)................. 130 ppm by volume on 1 hr minimum
liquid fuel. a dry basis sampling time.
corrected to 3
percent oxygen, 3-
run average; or (18
ppm by volume on a
dry basis corrected
to 3 percent
oxygen, 10-day
rolling average).
b. Filterable PM (or TSM)....... 1.3E-03 lb per MMBtu Collect a minimum of
of heat input; or 3 dscm per run.
(7.5E-05 lb per
MMBtu of heat
input).
15. Units designed to burn light a. CO (or CEMS)................. 130 \a\ ppm by 1 hr minimum
liquid fuel. volume on a dry sampling time.
basis corrected to
3 percent oxygen;
or (60 ppm by
volume on a dry
basis corrected to
3 percent oxygen, 1-
day block average)..
b. Filterable PM (or TSM)....... 1.1E-03 \a\ lb per Collect a minimum of
MMBtu of heat 3 dscm per run.
input; or (2.9E-05
lb per MMBtu of
heat input).
16. Units designed to burn liquid a. CO........................... 130 ppm by volume on 1 hr minimum
fuel that are non-continental a dry basis sampling time.
units. corrected to 3
percent oxygen, 3-
run average based
on stack test; or
(91 ppm by volume
on a dry basis
corrected to 3
percent oxygen, 3-
hour rolling
average).
[[Page 7213]]
b. Filterable PM (or TSM)....... 2.3E-02 lb per MMBtu Collect a minimum of
of heat input; or 2 dscm per run.
(8.6E-04 lb per
MMBtu of heat
input).
17. Units designed to burn gas 2 a. CO........................... 130 ppm by volume on 1 hr minimum
(other) gases. a dry basis sampling time.
corrected to 3
percent oxygen.
b. HCl.......................... 1.7E-03 lb per MMBtu For M26A, Collect a
of heat input. minimum of 2 dscm
per run; for M26,
collect a minimum
of 240 liters per
run.
c. Mercury...................... 7.9E-06 lb per MMBtu For M29, collect a
of heat input. minimum of 3 dscm
per run; for M30A
or M30B, collect a
minimum sample as
specified in the
method; for ASTM
D6784 \b\ collect a
minimum of 3 dscm.
d. Filterable PM (or TSM)....... 6.7E-03 lb per MMBtu Collect a minimum of
of heat input; or 3 dscm per run.
(2.1E-04 lb per
MMBtu of heat
input).
----------------------------------------------------------------------------------------------------------------
\a\ If you are conducting stack tests to demonstrate compliance and your performance tests for this pollutant
for at least 2 consecutive years show that your emissions are at or below this limit and you are not required
to conduct testing for CEMS or CPMS monitor certification, you can skip testing according to Sec. 63.7515 if
all of the other provision of Sec. 63.7515 are met. For all other pollutants that do not contain a footnote
``a'', your performance tests for this pollutant for at least 2 consecutive years must show that your
emissions are at or below 75 percent of this limit in order to qualify for skip testing.
\b\ Incorporated by reference, see Sec. 63.14.
[FR Doc. 2012-31646 Filed 1-30-13; 8:45 am]
BILLING CODE 6560-50-P
